Signal operated isolation valve

ABSTRACT

A method of drilling a wellbore includes drilling the wellbore through a formation by injecting drilling fluid through a drill string and rotating a drill bit. The drill string includes a shifting tool, a receiver in communication with the shifting tool, and the drill bit. The method further includes retrieving the drill string from the wellbore through a casing string until the shifting tool reaches an actuator. The casing string includes an isolation valve in an open position and the actuator. The method further includes sending a wireless instruction signal to the receiver. The shifting tool engages the actuator in response to the receiver receiving the instruction signal. The method further includes operating the actuator using the engaged shifting tool, thereby closing the isolation valve and isolating the formation from an upper portion of the wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation application of co-pending U.S. Ser.No. 14/659,955, filed on Mar. 17, 2015, which is a divisional of U.S.Ser. No. 13/227,847, filed on Sep. 8, 2011, which claims the benefit ofU.S. Prov. Pat. App. No. 61/384,493, entitled “Signal Operated IsolationValve”, filed on Sep. 20, 2010. The aforementioned applications areherein incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION Field of the Invention

Embodiments of the invention generally relate to a signal operatedisolation valve.

Description of the Related Art

A hydrocarbon bearing formation (i.e., crude oil and/or natural gas) isaccessed by drilling a wellbore from a surface of the earth to theformation. After the wellbore is drilled to a certain depth, steelcasing or liner is typically inserted into the wellbore and an annulusbetween the casing/liner and the earth is filled with cement. Thecasing/liner strengthens the borehole, and the cement helps to isolateareas of the wellbore during further drilling and hydrocarbonproduction.

Once the wellbore has reached the formation, the formation is thenusually drilled in an overbalanced condition meaning that the annuluspressure exerted by the returns (drilling fluid and cuttings) is greaterthan a pore pressure of the formation. Disadvantages of operating in theoverbalanced condition include expense of the drilling mud and damage toformations by entry of the mud into the formation. Therefore,underbalanced or managed pressure drilling may be employed to avoid orat least mitigate problems of overbalanced drilling. In underbalancedand managed pressure drilling, a light drilling fluid, such as liquid orliquid-gas mixture, is used instead of heavy drilling mud so as toprevent or at least reduce the drilling fluid from entering and damagingthe formation. Since underbalanced and managed pressure drilling aremore susceptible to kicks (formation fluid entering the annulus),underbalanced and managed pressure wellbores are drilled using arotating control device (RCD) (aka rotating diverter, rotating BOP,rotating drilling head, or PCWD). The RCD permits the drill string to berotated and lowered therethrough while retaining a pressure seal aroundthe drill string.

An isolation valve located within the casing/liner may be used totemporarily isolate a formation pressure below the isolation valve suchthat a drill or work string may be quickly and safely inserted into aportion of the wellbore above the isolation valve that is temporarilyrelieved to atmospheric pressure. An example of an isolation valvehaving a flapper is discussed and illustrated in U.S. Pat. No.6,209,663, which is incorporated by reference herein in its entirety. Anexample of an isolation valve having a ball is discussed and illustratedin U.S. Pat. No. 7,204,315, which is incorporated by reference herein inits entirety. The isolation valve allows a drill/work string to betripped into and out of the wellbore at a faster rate than snubbing thestring in under pressure. Since the pressure above the isolation valveis relieved, the drill/work string can trip into the wellbore withoutwellbore pressure acting to push the string out. Further, the isolationvalve permits insertion of the drill/work string into the wellbore thatis incompatible with the snubber due to the shape, diameter and/orlength of the string.

Actuation systems for the isolation valve are typically hydraulicrequiring one or two control lines that extend from the isolation valveto the surface. The control lines require crush protection, aresusceptible to leakage, and would be difficult to route through a subseawellhead.

SUMMARY OF THE INVENTION

Embodiments of the invention generally relate to a signal operatedisolation valve. In one embodiment, a method of drilling a wellboreincludes drilling the wellbore through a formation by injecting drillingfluid through a drill string and rotating a drill bit. The drill stringincludes a shifting tool, a receiver in communication with the shiftingtool, and the drill bit. The method further includes retrieving thedrill string from the wellbore through a casing string until theshifting tool reaches an actuator. The casing string includes anisolation valve in an open position and the actuator. The method furtherincludes sending a wireless instruction signal to the receiver. Theshifting tool engages the actuator in response to the receiver receivingthe instruction signal. The method further includes operating theactuator using the engaged shifting tool, thereby closing the isolationvalve and isolating the formation from an upper portion of the wellbore.

In another embodiment, a method of drilling a wellbore includes drillingthe wellbore through a formation by injecting drilling fluid through adrill string and rotating a drill bit and retrieving the drill stringfrom the wellbore through a casing string until the drill bit is above aclosure member. The casing string includes the closure member in an openposition and an actuator. The method further includes sending a wirelessinstruction signal to the actuator; and closing the closure member,thereby isolating the formation from an upper portion of the wellbore.

In another embodiment, an actuator for use in a wellbore includes: atubular housing having a bore formed therethrough; a power source; areceiver for receiving a wireless instruction signal; a controller incommunication with the power source and antenna; a pump or pistonoperable to supply pressurized hydraulic fluid to an isolation valve; aposition or proximity sensor in communication with the controller fordetermining a position of the isolation valve; and a lock operablyconnected to the pump or piston and the controller. The controller isoperable to release the lock in response to receiving the instructionsignal.

In another embodiment, a shifting tool for use in a wellbore includes: atubular housing having a bore formed therethrough and a pocket formed ina wall thereof; a driver moveable relative to the housing between anextended position and a retracted position and disposed in the pocket inthe retracted position; a piston disposed in the housing, longitudinallymovable relative thereto between an engaged position and a disengagedposition, and operable to extend the driver when moving from thedisengaged position to the engaged position; a lock operable to retainthe piston in the engaged position; and an actuator operable to releasethe lock in response to receiving an instruction signal.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIGS. 1A-C are cross-sections of an isolation assembly in the closedposition, according to one embodiment of the present invention.

FIG. 2A is a cross-section of a shifting tool for actuating theisolation assembly between the positions, according to anotherembodiment of the present invention. FIGS. 2B and 2C illustrate atelemetry sub for use with the shifting tool. FIG. 2D is an enlargementof a portion of FIG. 2A.

FIG. 3A illustrates an electronics package of the telemetry sub. FIG. 3Billustrates an active RFID tag for use with the telemetry sub. FIG. 3Cillustrates a passive RFID tag for use with the telemetry sub. FIG. 3Dillustrates a Wireless Identification and Sensing Platform (WISP) RFIDtag for use with the telemetry sub. FIG. 3E illustrates accelerometersof the telemetry sub. FIG. 3F illustrates a mud pulser of the telemetrysub.

FIG. 4A illustrates a power sub for use with the isolation assembly,according to another embodiment of the present invention. FIGS. 4B-4Eillustrate operation of the power sub.

FIG. 5 illustrates a position indicator for the isolation valve,according to another embodiment of the present invention.

FIGS. 6A and 6B illustrate an isolation valve in the closed position,according to another embodiment of the present invention. FIG. 6C is anenlargement of a portion of FIG. 6A.

FIG. 7A illustrates another way of operating the isolation valve,according to another embodiment of the present invention. FIG. 7Billustrates a charger for use with an isolation valve, according toanother embodiment of the present invention. FIG. 7C is an isometricview of the charger of FIG. 7B. FIG. 7D illustrates another charger foruse with an isolation valve, according to another embodiment of thepresent invention. FIG. 7E illustrates another charger for use with anisolation valve, according to another embodiment of the presentinvention. FIG. 7F is an enlargement of the charger. FIG. 7G is across-section illustrating two layers of the charger.

FIGS. 8A-C illustrate another isolation assembly in the closed position,according to another embodiment of the present invention.

FIGS. 9A-C illustrate another isolation assembly in the closed position,according to another embodiment of the present invention. FIGS. 9D and9E illustrate operation of an actuator of the isolation assembly.

FIGS. 10A and 10B illustrate a portion of another isolation valve in theopen and closed positions, respectively, according to another embodimentof the present invention.

FIG. 11A illustrates a drilling rig for drilling a wellbore, accordingto another embodiment of the present invention. FIGS. 11B-11I illustratea method of drilling and completing a wellbore using the drilling rig.

FIG. 12A illustrates a portion of a power sub for use with the isolationassembly in a retracted position, according to another embodiment of thepresent invention. FIG. 12B illustrates a portion of the power sub in anextended position.

FIG. 13A is a cross-section of a shifting tool for actuating theisolation assembly between the positions, according to anotherembodiment of the present invention. FIGS. 13B and 13C illustrate aportion of an isolation valve in the closed position, according toanother embodiment of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

FIGS. 1A-C are cross-sections of an isolation assembly in the closedposition, according to one embodiment of the present invention. Theisolation assembly may include one or more power subs 1, a spacer sub25, and the isolation valve 50. The isolation assembly may be assembledas part of a casing 1015 or liner string and run-into a wellbore 1005(see FIG. 11B). The casing 1015 or liner string may be cemented in thewellbore 1005 or be a tie-back casing string. Although only one powersub 500 is shown, two power subs may be used in a three-wayconfiguration, discussed below.

The power sub 1 may include a tubular housing 5 and a tubular mandrel10. The housing 5 may have couplings (not shown) formed at eachlongitudinal end thereof for connection with other components of thecasing/liner string. The couplings may be threaded, such as a box and apin. The housing 5 may have a central longitudinal bore formedtherethrough. Although shown as one piece, the housing 5 may include twoor more sections to facilitate manufacturing and assembly, each sectionconnected together, such as fastened with threaded connections.

The mandrel 10 may be disposed within the housing 5 and longitudinallymovable relative thereto. The mandrel 10 may have a profile 10 p formedin an inner surface thereof for receiving a cleat 130 of a shifting tool100. The mandrel 10 may further have one or more position indicators 15p,

embedded in an inner surface thereof and the housing 5 may have one ormore position indicator 15 h embedded in an inner surface thereof.Alternatively, the indicator 15 h may instead be embedded in an innersurface of the spacer housing 30. The mandrel 10 may further have apiston shoulder 10 s formed in or fastened to an outer surface thereof.The piston shoulder 10 s may be disposed in a chamber 6. The housing 5may further have upper 5 u and lower 5

shoulders formed in an inner surface thereof. The chamber 6 may bedefined radially between the mandrel 10 and the housing 5 andlongitudinally between an upper seal disposed between the housing 5 andthe mandrel 10 proximate the upper shoulder 5 u and a lower sealdisposed between the housing 5 and the mandrel 10 proximate the lowershoulder 5

. Hydraulic fluid may be disposed in the chamber 6. Each end of thechamber 6 may be in fluid communication with a respective hydrauliccoupling 9 c via a respective hydraulic passage 9 p formedlongitudinally through a wall of the housing 5.

The spacer sub 25 may include a tubular housing 30 having couplings (notshown) formed at each longitudinal end thereof for connection with thepower sub 1 and the isolation valve 50. The couplings may be threaded,such as a pin and a box. The spacer sub 25 may further include hydraulicconduits, such as tubing 29 t, fastened to an outer surface of thehousing 30 and hydraulic couplings 29 c connected to each end of thetubing 29 t. The hydraulic couplings 29 c may mate with respectivehydraulic couplings of the power sub 1 and the isolation valve 50. Thespacer sub 25 may provide fluid communication between a respective powersub passage 9 p and a respective isolation valve passage 59 p. Thespacer sub 25 may also have a length sufficient to accommodate the BHAof the drill string while the shifting tool 100 is engaged with thepower sub 1, thereby providing longitudinal clearance between the drillbit and a flapper 70. The spacer sub length may depend on the length ofthe BHA.

The isolation valve 50 may include a tubular housing 55, a flow tube 60,and a closure member, such as the flapper 70. As discussed above, theclosure member may be a ball (not shown) instead of the flapper 70. Tofacilitate manufacturing and assembly, the housing 55 may include one ormore sections 55 a,b each connected together, such as fastened withthreaded connections and/or fasteners. The housing 55 may furtherinclude an upper adapter (not shown) connected to section 55 a forconnection to the spacer sub 25 and a lower adapter (not shown)connected to the section 55 b for connection with casing or liner. Thehousing 55 may have a longitudinal bore formed therethrough for passageof a drill string.

The flow tube 60 may be disposed within the housing 55. The flow tube 60may be longitudinally movable relative to the housing 55. A piston 61may be formed in or fastened to an outer surface of the flow tube 60.The piston 61 may include one or more seals for engaging an innersurface of a chamber 57 formed in the housing 55 and one or more sealsfor engaging an outer surface of the flow tube 60. The housing 55 mayhave upper 55 u and lower 55

shoulders formed in an inner surface thereof. The chamber 57 may bedefined radially between the flow tube 60 and the housing 55 andlongitudinally between an upper seal disposed between the housing 55 andthe flow tube 60 proximate the upper shoulder 55 u and a lower sealdisposed between the housing 55 and the flow tube proximate the lowershoulder 55

. Hydraulic fluid may be disposed in the chamber 57. Each end of thechamber 57 may be in fluid communication with a respective hydrauliccoupling 59 c via a respective hydraulic passage 59 p formed through awall of the housing 55.

The flow tube 60 may be longitudinally movable by the piston 61 betweenthe open position and the closed position. In the closed position, theflow tube 60 may be clear from the flapper 70, thereby allowing theflapper 70 to close. In the open position, the flow tube 60 may engagethe flapper 70, push the flapper 70 to the open position, and engage aseat 58 s formed in the housing 55. Engagement of the flow tube 60 withthe seat 58 s may form a chamber 56 between the flow tube 60 and thehousing 55, thereby protecting the flapper 70 and the flapper seat 56 s.The flapper 70 may be pivoted to the housing 55, such as by a fastener70 p. A biasing member, such as a torsion spring (not shown), may engagethe flapper 70 and the housing 55 and be disposed about the fastener 70p to bias the flapper 70 toward the closed position. In the closedposition, the flapper 70 may fluidly isolate an upper portion of thevalve from a lower portion of the valve.

FIG. 2A is a cross-section of a shifting tool 100 for actuating theisolation assembly between the positions, according to anotherembodiment of the present invention. FIG. 2D is an enlargement of aportion of FIG. 2A. The shifting tool 100 may include a tubular housing105, a tubular piston 110, and one or more longitudinal drivers, such ascleats 130, and an actuator, such as a hydraulic lock 150. The housing105 may have couplings 107 b,p formed at each longitudinal end thereoffor connection with other components of a drill string. The couplingsmay be threaded, such as a box 107 b and a pin 107 p. The housing 105may have a central longitudinal bore formed therethrough for conductingdrilling fluid. The housing 105 may include one or more sections (onlyone section shown) to facilitate manufacturing and assembly, eachsection connected together, such as fastened with threaded connections.An inner surface of the housing 105 may have an upper 105 u and lower105

shoulder formed therein.

The piston 110 may be disposed within the housing 105 and longitudinallymovable relative thereto between a retracted position (shown) and anengaged position. The piston 110 may have a top 110 t, one or moreprofiles, such as slots 110 s, formed in an outer surface thereof, oneor more lugs 110 g formed in an outer surface thereof, and a shoulder110

formed in an outer surface thereof. One or more fasteners, such as pins118, may be disposed through respective holes formed through a wall ofthe housing and extend into the respective slots 110 s, therebyrotationally connecting the piston 110 to the housing 105. In theretracted position, the piston top 110 t may be stopped by engagementwith a fastener, such as a ring 117, connected to the housing 105, suchas by a threaded connection. The stop ring 117 may engage the upperhousing shoulder 105 u. The piston top 105 t may have an area greaterthan an area of a bottom of the piston.

One or more ribs 105 r may be formed in an outer surface of the housing105 and spaced therearound. A pocket 105 p may be formed through eachrib 105 r. The cleat 130 may be disposed in the pocket 105 p in theretracted position. The cleat 130 may be moved outward toward to theengaged position by one or more pushers, such as wedges 115, disposed inthe pocket 105 p. Each wedge 115 may include an inner slip 115 i and anouter slip 115 o. The inner slip 115 i may be connected to the pistonlug 110 g, such as by a fastener 116 i. The outer slip 115 o may beconnected to the cleat 130, such as by a fastener 116 o. A clearance maybe provided between the cleat 130 and the outer slip 115 o and/orfastener 116 o and a biasing member, such as a Bellville spring 131, maybe disposed between the outer slip 115 o and the cleat 130 to bias thecleat 130 into engagement with the fastener 116 o. A seal may bedisposed between the cleat 130 and the housing 105.

An upper chamber may be defined radially between the piston 110 and thehousing 105 and may include the pocket 105 p. The upper chamber may belongitudinally defined between one or more upper seals disposed betweenthe housing 105 and the piston 110 proximate the piston top 110 t andone or more intermediate seals disposed between the housing 105 and thepiston 110 proximate the lower shoulder 110

. Hydraulic fluid may be disposed in the upper chamber. A compensatorpiston 160 may be disposed in a passage 159 v formed through a wall ofthe housing 105. A lower face of the compensator piston 160 may be influid communication with an exterior of the shifting tool 100 (i.e., theannulus 1025 (FIG. 11C) when disposed in the wellbore 1005) and an upperface of the compensator piston may be in fluid communication with theupper chamber. The compensator piston 160 may serve to equalize pressureof the hydraulic fluid with annulus pressure and to account for changesin volume of the upper chamber due to temperature and/or movement of thecleat 130. A biasing member, such as a coil spring 140, may be disposedagainst the lower shoulders 110

, 105

, thereby biasing the piston 110 toward the retracted position. The coilspring may 140 may be disposed in a lower chamber longitudinally definedbetween the intermediate seals and a lower seal disposed between thehousing 105 and the piston 110 proximate the lower housing shoulder 105

and radially between the piston 110 and the housing 105. Hydraulic fluidmay be disposed in the lower chamber.

The hydraulic lock 150 may include one or more passages 159 c,o formedthrough a wall of the housing 105 and one or more valves 152, 154interconnected with the respective passages 159 c,o. The hydraulic lock150 may provide selective fluid communication between the upper andlower chambers. The valve 154 may be a check valve operable to allowfluid flow from the upper chamber to the lower chamber and prevent fluidflow from the lower chamber to the upper chamber. The valve 152 may be acontrol valve, such as a solenoid operated shutoff valve, operablebetween an open position and a closed position. The shutoff valve 152may bi-directionally prevent flow between the upper and lower chambersin the closed position and bi-directionally allow flow between thechambers in the open position. The solenoid may be biased toward theclosed position. Lead wires 155 may extend from the control valve 152 tothe pin 107 p. An electrical coupling 107 c may be disposed in the pin107 p for receiving electricity from the telemetry sub 200. The coupling107 c may be inductive or contact rings.

Alternatively, the control valve 152 may be a solenoid operated checkvalve and the check valve 154 and corresponding passage 159 c may beomitted. The solenoid operated check valve may operate as a check valvein the closed position and allow bi-directional flow in the openposition. Alternatively, the actuator 150 may be an electromechanicallock (see actuator 750, discussed below).

FIGS. 2B and 2C illustrate a telemetry sub 200 for use with the shiftingtool 100. The telemetry sub 200 may include an upper adapter 205 a, oneor more auxiliary sensors 202 a,b, a pressure sensor 204, a downlinkhousing 205 b, a sensor housing 205 c, a pressure sensor 204, a downlinkmandrel 210, an uplink housing 205 d, a lower adapter 205 e, one or moreelectrical couplings 209 a-e, an electronics package 225, a battery 231,one or more antennas 226 i,o, a tachometer 255, and a mud pulser 275.The housings 205 b-d may each be modular so that any of the housings 205b-d may be omitted and the rest of the housings may be used togetherwithout modification thereof. Alternatively, any of the sensors orelectronics of the telemetry sub 200 may be incorporated into theshifting tool 100 and the telemetry sub 200 may be omitted.

The adapters 205 a,e may each be tubular and have a threaded coupling,such as a pin 207 p and a box 207 b, formed at a longitudinal endthereof for connection with the shifting tool 100 and another componentof the drill string. The electrical coupling 209 a may be disposed inthe box 207 b for transmitting electricity to the control valve 152. Thecouplings 209 a-e may be inductive or contact rings. Alternatively, awet or dry pin and socket connection may be used to connect thetelemetry sub 200 and the shifting tool 100 instead of the pin and box.Lead wires 208 may connect the couplings 209 a,b and the othercomponents with the electrical couplings. Each housing 205 a-e may belongitudinally and rotationally connected together by one or morefasteners, such as screws (not shown), and sealed by one or more seals,such as o-rings (not shown).

The sensor housing 205 c may house the pressure sensor 204 and thetachometer 255. The pressure sensor 204 may be in fluid communicationwith a bore of the sensor housing 205 c via a first port and in fluidcommunication with the annulus via a second port. Additionally, thepressure sensor 204 may also measure temperature of the drilling fluidand/or returns. The sensors 204,255 may be in data communication withthe electronics package 225 by engagement of the contacts 207 c disposedat a top of the mandrel 210 with corresponding contacts 207 c disposedat a bottom of the downlink housing 205 b. The sensors 204,255 may alsoreceive electrical power via the contacts. The sensor housing 205 c mayalso relay data between the mud pulser 275, the auxiliary sensors 202,and the electronics package 225 via leads 208 and radial contacts 209d,e. The auxiliary sensors 202 may be magnetometers which may be usedwith the tachometer 255 for determining directional information duringdrilling, such as azimuth, inclination, and/or tool face/bent sub angle.

Each antenna 226 i,o may include an inner liner, a coil, and an outersleeve disposed along an inner surface of the downlink mandrel 210 orthe downlink housing 205 b. The liner may be made from a non-magneticand non-conductive material, such as a polymer or composite, have a boreformed longitudinally therethrough, and have a helical groove formed inan outer surface thereof. The coil may be wound in the helical grooveand made from an electrically conductive material, such as a metal oralloy. The outer sleeve may be made from the non-magnetic andnon-conductive material and may be insulate the coil from the downlinkmandrel 210 or downlink housing 205 b. The antennas 226 i,o may belongitudinally and rotationally connected to the downlink mandrel 206and sealed from a bore of the telemetry sub 200.

FIG. 3A illustrates the electronics package 225. FIG. 3B illustrates anactive RFID tag 250 a for use with the telemetry sub 200. FIG. 3Cillustrates a passive RFID tag 250 p for use with the telemetry sub 200.FIG. 3D illustrates a wireless identification and sensing platform(WISP) RFID tag 250 w for use with the telemetry sub 200. Theelectronics package 225 may communicate with any of the RFID tags 250a,p,w. Any of the RFID tags 250 a,p,w may be individually encased anddropped or pumped through the drill string. The electronics package 225may be in electrical communication with the antennas 226 i,o and receiveelectricity from the battery 231. The electronics package 225 mayinclude an amplifier 227, a filter and detector 228, a transceiver 229,a microprocessor 230, an RF switch 234, a pressure switch 233, and an RFfield generator 232. Alternatively, the tags 250 a,p,w and electronicspackage 225 may operate on any other wireless frequency, such asacoustic.

The pressure switch 233 may remain open at the surface to prevent theelectronics package 225 from becoming an ignition source. Once thetelemetry sub 200 is deployed to a sufficient depth in the wellbore, thepressure switch 233 may close. The microprocessor 230 may also detectdeployment in the wellbore using pressure sensor 205. The microprocessor230 may delay activation of the transmitter for a predetermined periodof time to conserve the battery 231.

When it is desired to operate the shifting tool 100, one of the tags 250a,p,w may be pumped or dropped from the drilling rig 1000 (FIG. 11A) tothe antenna 226 i. If a passive 250 p or WISP tag 250 w is deployed, themicroprocessor 230 may begin transmitting a signal and listening for aresponse. Once the tag 250 p,w is deployed into proximity of the antenna226 i, the tag 250 p,w may receive the signal, convert the signal toelectricity, and transmit a response signal. The antenna 226 i mayreceive the response signal and the electronics package 225 may amplify,filter, demodulate, and analyze the signal. If the signal matches apredetermined instruction signal, then the microprocessor 230 mayoperate the control valve 152 by supplying electricity thereto. Theinstruction signal carried by the tag 250 a,p,w may include a command,such as to extend or retract the cleat 130. If an active tag 250 a isused, then the tag 250 a may include its own battery, pressure switch,and timer so that the tag 250 a may perform the function of thecomponents 232-234.

The WISP tag 250 w may include a date and time stamp so that multipletags may be pumped for redundancy. In this manner, if any of the tagsbecome stuck in the wellbore and later dislodged, the microprocessor 230may know to disregard the command if it has already received the commandwith the same or a later date and time stamp.

FIG. 3E is a schematic cross-sectional view of the sensor module. Thetachometer 255 may include two diametrically opposed single axisaccelerometers 255 a,b. The accelerometers 255 a,b may be piezoelectric,magnetostrictive, servo-controlled, reverse pendular, ormicroelectromechanical (MEMS). The accelerometers 255 a,b may beradially X oriented to measure the centrifugal acceleration Ac due torotation of the telemetry sub 200 for determining the angular speed. Thesecond accelerometer may be used to account for gravity G if thetelemetry sub 200 is used in a deviated or horizontal wellbore.Alternatively, the accelerometers 255 a,b may be tangentially Yoriented, dual axis, and/or asymmetrically arranged (not diametricand/or each accelerometer at a different radial location). Further, theaccelerometers 255 a,b may be used to calculate borehole inclination andgravity tool face during drilling. Further, the sensor module mayinclude a longitudinal Z accelerometer. Alternatively, magnetometers maybe used instead of accelerometers to determine the angular speed.

Instead of using one of the RFID tags 250 a,p,w to activate the shiftingtool 100, an instruction signal may be sent to the controller 230 bymodulating angular speed of the drill string according to apredetermined protocol. The modulated angular speed may be detected bythe tachometer 255. The microporcessor 230 may then demodulate thesignal and operate the shifting tool 100. The protocol may representdata by varying the angular speed on to off, a lower speed to a higherspeed and/or a higher speed to a lower speed, or monotonicallyincreasing from a lower speed to a higher speed and/or a higher speed toa lower speed.

FIG. 3F illustrates the mud pulser 275. The mud pulser 275 may include avalve, such as a poppet 276, an actuator 277, a turbine 278, a generator279, and a seat 280. The poppet 276 may be longitudinally movable by theactuator 277 relative to the seat 280 between an open position (shown)and a choked position (dashed) for selectively restricting flow throughthe pulser 275, thereby creating pressure pulses in drilling fluidpumped through the mud pulser. The mud pulses may be detected at thesurface, thereby communicating data from the microprocessor 230 to thesurface. The turbine 278 may harness fluid energy from the drillingfluid pumped therethrough and rotate the generator 279, therebyproducing electricity to power the mud pulser 275. The mud pulser 275may be used to send confirmation of receipt of commands and reportsuccessful execution of commands or errors to the surface. Theconfirmation may be sent during circulation of drilling fluid.Alternatively, a negative or sinusoidal mud pulser may be used insteadof the positive mud pulser 275. The microprocessor 230 may also use theturbine 278 and/or pressure sensor 204 as a flow switch and/or flowmeter.

Instead of using one of the RFID tags 250 a,p,w or angular speedmodulation to activate the shifting tool 100, a signal may be sent tothe microporcessor 230 by modulating a flow rate of the rig drillingfluid pump according to a predetermined protocol. Alternatively, a mudpulser (not shown) may be installed in the rig pump outlet and operatedby a surface controller 1070 (FIG. 11A) to send pressure pulses from thedrilling rig 1000 to the telemetry sub microprocessor 230 according to apredetermined protocol. The microprocessor 230 may use the turbineand/or pressure sensor as a flow switch and/or flow meter to detect thesequencing of the rig pumps/pressure pulses. The flow rate protocol mayrepresent data by varying the flow rate on to off, a lower speed to ahigher speed and/or a higher speed to a lower speed, or monotonicallyincreasing from a lower speed to a higher speed and/or a higher speed toa lower speed. Alternatively, an orifice flow switch or meter may beused to receive pressure pulses/flow rate signals communicated throughthe drilling fluid from the rig 1000 instead of the turbine 278 and/orpressure sensor 204. Alternatively, the sensor sub may detect thepressure pulses/flow rate signals using the pressure sensor 204 andaccelerometers 255 a,b to monitor for BHA vibration caused by thepressure pulse/flow rate signal.

Alternatively, an electromagnetic (EM) gap sub (not shown) may be usedinstead of the mud pulser 275, thereby allowing data to be transmittedto the microprocessor and/or to surface using EM waves. Alternatively, atransverse EM antenna may be used instead of the EM gap sub.Alternatively, an RFID tag launcher (not shown) may be used instead ofthe mud pulser. The tag launcher may include one or more RFID tags 250w. The microprocessor 230 may then encode the tags with data and thelauncher may release the tags to the surface. Alternatively, an acoustictransmitter may be used instead of the mud pulser. For deeper wells, thedrill string may further include a signal repeater (not shown) toprevent attenuation of the transmitted mud pulse. The repeater maydetect the mud pulse transmitted from the mud pulser 475 and include itsown mud pulser for repeating the signal. As many repeaters may bedisposed along the workstring as necessary to transmit the data to thesurface, e.g., one repeater every five thousand feet. The repeaters maybe used for any of the mud pulser alternatives, discussed above.Repeating the transmission may increase bandwidth for the particulardata transmission. Alternatively, the telemetry sub may send and receiveinstructions via wired drill string.

In operation, the shifting tool 100 and telemetry sub 200 may beassembled as part of the drill string 1050. The drill string 1050 may berun into the wellbore 1005 and the microprocessor 230 may begintransmitting a signal to search for the indicator 15 p. Conversely, ifthe valve 50 is being closed after drilling, the microprocessor 230 maybe searching for the indicator 15 h to indicate proximity to the profile10 p. The indicators 15 p,

,h may each be an RFID tag, such as a passive tag 250 p. The indicator15 p may be operable to respond with a signal indicating location at theprofile and the indicator 15

may be located to correspond to the outer antenna when the cleat 130 isengaged with the profile. Once the outer antenna 226 o is in range ofthe indicator 15 p, the indicator 15 p may respond, thereby informingthe microprocessor 230 of proximity to the profile 10 p. Themicroprocessor 230 may send a signal to the rig 1000, such as by usingthe mud pulser 275. The shifting tool 100 may continue to be lowereduntil the microprocessor 230 detects the lower indicator 15

and sends a signal to the rig 1000 indicating alignment of the cleat 130with the profile 10 p.

An instruction signal may then be sent to the telemetry sub 200 by anyof the ways, discussed above, such as by pumping the RFID tag 250 pthrough the drill string 1050 or modulating rotation of the drillstring. Once the signal is sent, drilling fluid may be pumped/continuedto be pumped through the drill string, thereby creating a pressuredifferential between pressure in the drill string 1050 and pressure inthe annulus 1025 due to pressure loss through the drill bit 1050 b. Thispressure differential may exert a net downward force on the shiftingtool piston 110 which may be hydraulically locked by the closed controlvalve 152.

Once the telemetry sub 200 receives the signal and opens the controlvalve 152, the net pressure force may drive the piston 110longitudinally downward and move the inner slips 115 i relative to theouter slips 115 o. The fasteners 1160 may be wedged outward by therelative longitudinal movement of the slips 115 i,o. The fasteners 116 omay push the cleat 130 into engagement with the power sub profile 10 p.Engagement of the cleat 130 with the profile 10 p may longitudinallyconnect the shifting tool 100 and the power sub mandrel 10. Thelongitudinal connection may be bi-directional or uni-directional. Theshifting tool 100 may be lowered (or lowering may continue), therebyalso moving the power sub mandrel 10 longitudinally downward andactuating the isolation valve 50. If only one power sub is used(bi-directional connection), then the shifting tool 100 may be raised orlowered depending on the last position of the isolation valve 50. Use oftwo-power subs 1 in the three-way configuration in conjunction with theuni-directional (downward) connection advantageously allows retrieval ofthe drill string in the event of emergency and/or malfunction of thepower subs 1 and/or shifting tool 100 by simply pulling up on the drillstring 1050.

Actuation of the power sub 1 may be verified by again detecting theindicator 15

. If the cleat 130 did not engage with the profile 10 p, then detectionof the indicator 15

may not occur because the indicator is out of range or themicroprocessor 230 may detect that the indicator is further away than itshould be. Once actuation has been verified, the microprocessor 230 mayreport to the surface. The rig 1000 may then send an instruction signalto the microprocessor to retract the cleat 130. The microprocessor maythen close the control valve 152 and circulation may be halted, therebyallowing retraction of the cleat.

Alternatively, a second instruction signal may be sent to the telemetrysub via a second wireless medium and the microprocessor 230 may notoperate the shifting tool until 100 receiving both instruction signals.Alternatively, the microprocessor may be programmed to autonomouslyextend the cleats in response to detection of the appropriateindicator(s) 15 p,

,h and/or autonomously retract the cleats in response to detection ofthe appropriate indicator(s). Alternatively or additionally, the powersub 1 may further include one or more latches, such as collets or dogs,disposed between the housing and the mandrel. The latch may offerresistance to initial movement of the mandrel relative to the housingdetectable at the surface and preventing unintentional actuation of thepower sub due to incidental contact with other components of the drillstring.

FIG. 4A illustrates a power sub 300 for use with the isolation assembly,according to another embodiment of the present invention. The power sub300 may include a tubular housing 305, a tubular mandrel 310, a piston315, a tubular driver 325, one or more indicators 340 a-c,u,h, and aclutch 350. The housing 305 may have couplings (not shown) formed ateach longitudinal end thereof for connection with the spacer sub 25, andother components of the casing/liner string. The couplings may bethreaded, such as a box and a pin. The housing 305 may have a centrallongitudinal bore formed therethrough. Although shown as one piece, thehousing 305 may include two or more sections to facilitate manufacturingand assembly, each section connected together, such as fastened withthreaded connections.

The mandrel 310 may be disposed within the housing 305, longitudinallyconnected thereto, and rotatable relative thereto. The cleat 130 of theshifting tool 100 may be replaced by a rotational driver (not shown) andthe mandrel 310 may have a profile 310 p formed in an inner surfacethereof for receiving the driver. The profile may be a series of slots310 p spaced around the mandrel inner surface. The slots 310 p may havea length greater than or substantially greater than a length of theshifting tool driver to provide an engagement tolerance and/or tocompensate for heave of the drill string 1050 for subsea drillingoperations. The mandrel 310 may further have one or more helicalprofiles 310 t formed in an outer surface thereof. If the mandrel 310has two or more helical profiles 310 t (two shown), then the helicalprofiles may be interwoven.

The piston 315 may be tubular and have a shoulder 315 s disposed in alower chamber 306 formed in the housing 305. The housing 305 may furtherhave upper 306 u and lower 306

shoulders formed in an inner surface thereof. The lower chamber 306 maybe defined radially between the piston 315 and the housing 305 andlongitudinally between an upper seal (not shown) disposed between thehousing 305 and the piston 315 proximate the upper shoulder 306 u and alower seal (not shown) disposed between the housing 305 and the piston315 proximate the lower shoulder 306

. A piston seal (not shown) may also be disposed between the pistonshoulder 315 s and the housing 305. Hydraulic fluid may be disposed inthe lower chamber 306. Each end of the chamber 306 may be in fluidcommunication with a respective hydraulic coupling (not shown) via arespective hydraulic passage 309 p formed longitudinally through a wallof the housing 305.

Two power subs 300 may be hydraulically connected to the isolation valve50 in a three-way configuration such that each of the power sub pistons315 are in opposite positions and operation of one of the power subs 300will operate the isolation valve 50 between the open and closedpositions and alternate the other power sub 300. This three wayconfiguration may allow each power sub 300 to be operated in only onerotational direction and each power sub 300 to only open or close theisolation valve 50. Respective hydraulic couplings of each power sub 300and the isolation valve 50 may be connected by a conduit, such as tubing(not shown).

FIGS. 4B-4E illustrate operation of the power sub 300. The helicalprofiles 310 t and the clutch 350 may allow the driver 325 tolongitudinally translate while not rotating while the mandrel 310 isrotated by the shifting tool and not translated. The clutch 350 mayinclude a tubular cam 335 and one or more followers 330. The cam 335 maybe disposed in an upper chamber 307 formed in the housing 305. Thehousing 305 may further have upper 307 u and lower 307

shoulders formed in an inner surface thereof. The chamber 307 may bedefined radially between the mandrel 310 and the housing 305 andlongitudinally between an upper seal disposed between the housing 305and the mandrel 310 proximate the upper shoulder 307 u and lower sealsdisposed between the housing 305 and the driver 325 and between themandrel 310 and the driver 325 proximate the lower shoulder 307

. Lubricant may be disposed in the chamber. A compensator piston (notshown) may be disposed in the mandrel 310 or the housing 305 tocompensate for displacement of lubricant due to movement of the driver325. The compensator piston may also serve to equalize pressure of thelubricant (or slightly increase) with pressure in the housing bore.

Each follower 330 may include a head 331, a base 333, and a biasingmember, such as a coil spring 332, disposed between the head 331 and thebase 333. Each follower 330 may be disposed in a hole 325 h formedthrough a wall of the driver 325. The follower 330 may be moved along atrack 335 t of the cam 335 between an engaged position (FIGS. 4B and4C), a disengaged position (FIG. 4E), and a neutral position (FIG. 4D).The follower base 333 may engage a respective helical profile 310 t inthe engaged position, thereby operably coupling the mandrel 310 and thedriver 325. The head 331 may be connected to the base 333 in thedisengaged position by a foot. The base 333 may have a stop (not shown)for engaging the foot to prevent separation.

The cam 335 may be longitudinally and rotationally connected to thehousing 305, such as by a threaded connection (not shown). The cam 335may have one or more tracks 335 t formed therein. When the driver 325 ismoving downward Md relative to the housing 305 and the mandrel 310 (fromthe piston upper position), each track 335 t may be operable to push andhold down a top of the respective head 331, thereby keeping the base 333engaged with the helical profile 310 t and when the driver 325 is movingupward Mu relative to the housing 305 and the mandrel 310, each track335 t may be operable to pull and hold up a lip of the head 331, therebykeeping the base 333 disengaged from the helical profile 310 t.

The driver 325 may be disposed between the mandrel 310 and the cam 335,rotationally connected to the cam 335, and longitudinally movablerelative to the housing 305 between an extended position (FIGS. 4A and4D) and a retracted position (FIG. 4B). A bottom of the driver 325 mayabut a top of the piston 315, thereby pushing the piston 315 from anupper position (FIG. 4A) to a lower position when moving from theretracted to the extended positions. When the follower base 333 isengaged with the helical profile 310 t (FIGS. 4B, 4C), rotation of themandrel 310 by engagement with the shifting tool may cause longitudinaldownward movement Md of the driver relative to the housing, therebypushing the piston 315 to the lower position. This conversion fromrotational motion to longitudinal motion may be caused by relativehelical motion between the follower base 333 and the helical profile 310t.

Once the follower 330 reaches a bottom of the helical profile 310 t andthe end of the track, the follower spring 332 may push the head 331toward the neutral position as continued rotation of the mandrel 310 maypush the follower base 333 into a groove 310 g formed around an outersurface of the mandrel 310, thereby disengaging the follower base 333from the helical profile 310 t. The follower 330 may float radially inthe neutral position so that the base 333 may or may not engage thegroove 310 g and/or remain in the groove 310 g. The groove 310 g mayensure that the mandrel 310 is free to rotate relative to the driver 325so that continued rotation of the mandrel 310 does not damage any of theshifting tool, the power sub 300, and the isolation valve 50.

Once the other power sub is operated by the shifting tool, fluid forcemay push the piston 315 toward the upper position, therebylongitudinally pushing the driver 325. The driver 325 may carry thefollower 330 along the track 335 t until the follower head 331 engagestrack 335 t. As discussed above, the track 335 t may engage the head lipand hold the base 333 out of engagement with the helical profile 310 tso that the mandrel 310 does not backspin as the driver 325 moveslongitudinally upward Mu relative thereto. Once the follower 330 reachesthe top of the second longitudinal track portion, the follower head 331may engage an inclined portion of the track 335 t where the follower 330is compressed until the base 333 engages the helical profile 310 t.

The indicators 340 a-c,u,h may each be passive RFID tags 250 p. Theindicators 340 u,h may perform a similar function to the indicators 15p,h and the indicators 340 a-c may perform a similar function to theindicator 15

. The indicator 340 c may indicate movement of the piston 315 while theindicators 340 a,b may be used to compensate for heave of the drillstring (discussed above). The indicators 340 a-c,u,

may further include a tool address to distinguish between the opener andcloser power sub of the three-way configuration, discussed above.

Alternatively, the microprocessor may be programmed to autonomouslyextend the drivers in response to detection of the appropriateindicator(s) 340 a-c,u,h and/or autonomously retract the drivers inresponse to detection of the appropriate indicator(s). Alternatively oradditionally, the power sub 300 may further include one or more latches,such as collets or dogs, disposed between the piston and the housing.The latch may offer resistance to initial movement of the pistonrelative to the housing detectable at the surface and preventingunintentional actuation of the power sub due to incidental contact withother components of the drill string.

FIG. 5 illustrates one or more position indicators 450 o,c for anisolation valve 400, according to another embodiment of the presentinvention. The isolation valve 400 may be similar to the isolation valve50 and include a housing 405, a flow tube 410, a flapper 420, and aflapper pivot 420 p. Relative to the isolation valve 50, an openindicator 450 o and a closed 450 c indicator have been added and theflow tube 410 has been modified. Instead of engaging the flapper 420,the flow tube 410 may be connected to the flapper by a linkage 413fastened to a lower end of the flow tube and the flapper, such as bypivoting. As the flow tube 410 is moved longitudinally by the piston(not shown, see piston 61), the linkage 413 may push or pull on theflapper, thereby rotating the flapper to the open or closed position.The flapper spring may be omitted.

Each indicator 450 o,c may include a chamber 451, a lever 455, a rod456, one or more biasing members, such as a rod coil spring 457 andvalve coil spring 458, a valve, such as a ball 459, and a piston, suchas a disk 460. One or more RFID tags, such as passive tags 250 p may bedisposed in the chamber 451 and written with a message that the flapperis open. The chamber 451 may be formed in the housing and selectivelyisolated from the housing bore by the valve 459 engaging a seat 452formed in the housing. Hydraulic fluid may be disposed in the chamber.The lever 455 may extend into the housing bore for engagement by abottom of the flow tube 410. The lever 455 may be fastened to thehousing 405, such as by pivoting. The rod 456 may be connected to thepiston 460 and extend through the valve 459 and the lever 455. One ormore seals (not shown) may be disposed between the piston 460 and thechamber 451. The rod 456 may be connected to the piston 460 by a ratchetand teeth such that the rod may move longitudinally upward relative tothe piston but not downward.

In operation, as the flow tube 410 is being moved downward to open theflapper 420, the flow tube bottom may engage the lever 455 and rotatethe lever about the pivot. The lever 455 may in turn push the rod 456against the rod spring 457, thereby causing the rod to pull the piston460 downward. Downward movement of the piston 460 may increase pressurein the chamber 451, thereby opening the valve 459 and expelling one ofthe RFID tags 250 p. The RFID tag 250 p may float upward and/or becarried upward by circulating drilling fluid 1045 f. The RFID tag 250 pmay be read by the outer antenna 226 o as the tag travels past thetelemetry sub 200. The telemetry sub 200 may then report to the rig1000. Alternatively or additionally, the tag 250 p may be read at therig 1000. As the flapper 420 completes opening, a groove 410 g formed inan outer surface of the flow tube 410 may become aligned with the lever455, thereby allowing the rod spring 457 to reset the lever. The disk460 may remain in the advanced position due to operation of the ratchetmechanism. During this stroke, the closer lever 455 may movelongitudinally downward; however, since the closer 450 c may be reversedfrom the opener 450 o, the ratchet mechanism may prevent movement of thecloser piston 460, thereby ensuring that the closer remains idle. Thecloser 460 c may be operated as the flapper 420 moves from the open tothe closed position (having one or more tags 250 p written with amessage that the flapper is closed). Alternatively, instead of RFID tags250 p, colored balls (i.e., red for closed and green for open) may bedisposed in the chambers 451 and observed at the rig 1000.

FIGS. 6A and 6B illustrate an isolation valve 500 in the closedposition, according to another embodiment of the present invention. FIG.6C is an enlargement of a portion of FIG. 6A. The isolation valve 500may include a tubular housing 505, a tubular piston 510, a flow tube515, a closure member, such as the flapper 520, and an actuator 550. Asdiscussed above, the closure member may be a ball (not shown) instead ofthe flapper 520. To facilitate manufacturing and assembly, the housing505 may include one or more sections 505 a-e each connected together,such as fastened with threaded connections and/or fasteners. The housing505 may further include an upper adapter (not shown) connected tosection 505 a and a lower adapter (not shown) connected to the section505 e for connection as part of the casing or liner. The housing 505 mayhave a longitudinal bore formed therethrough for passage of a drillstring.

The piston 510 and the flow tube 515 may each be disposed within thehousing 505. Each of the piston 510 and the flow tube 515 may belongitudinally movable relative to the housing 505. The piston 510 andthe flow tube 515 may be connected together, such as by coupling 512.Each of the piston 510 and the flow tube 515 may be fastened to thecoupling 512, such as by threads and/or fasteners. The piston 510 mayhave a shoulder 510 s formed in an outer surface thereof. The shoulder510 s may carry one or more seals for engaging an inner surface of achamber 507 formed in the housing 505. The housing 505 may have upper505 u and lower 505

shoulders formed in an inner surface thereof. The chamber 507 may bedefined radially between the piston 510 and the housing 505 andlongitudinally between an upper seal disposed between the housing 505and the piston 510 proximate the upper shoulder 505 u and a lower sealdisposed between the housing 505 and the piston 510 proximate the lowershoulder 505

. Hydraulic fluid may be disposed in the chamber 507. Each end of thechamber 507 may be in fluid communication with the actuator 550 via arespective hydraulic passage 553 u,

formed through a wall of the housing 505.

The flow tube 515 may be longitudinally movable by the piston 510between the open position and the closed position. In the closedposition, the flow tube 515 may be clear from the flapper 520, therebyallowing the flapper 520 to close. In the open position, the flow tube515 may engage the flapper 520, push the flapper 520 to the openposition, and engage a seat 523 formed in the housing 505. Engagement ofthe flow tube 515 with the seat 523 may form a chamber 506 between theflow tube 515 and the housing 505, thereby protecting the flapper 520and the flapper seat 522. The flapper 520 may be pivoted to the housing505, such as by a fastener 520 p. A biasing member, such as a torsionspring 521 may engage the flapper 520 and the housing 505 and bedisposed about the fastener 520 p to bias the flapper 520 toward theclosed position. In the closed position, the flapper 520 may fluidlyisolate an upper portion of the valve from a lower portion of the valve.

The actuator 550 may include an electronics package 525, a battery 531,an antenna 526, an electric motor 558, a hydraulic pump 552, and aposition sensor 555. The electronics package 525 and the antenna 526 maybe similar to the electronics package 225 and the antenna 226 i,respectively. The pump 552 may be in communication with the passages 553u,

and operable to hydraulically move the shoulder 510 s longitudinallybetween the closed position and the open position. The pump 552 mayinclude a piston and cylinder and connected to the motor 558 by a nutand lead screw. Alternatively, the motor 558 may be a linear motorinstead of a rotary motor. Additionally, the actuator 550 may include asolenoid operated valve 557 or solenoid operated latch for locking thevalve at the open and closed positions to prevent unintentionalactuation of the valve due to incidental contact with the drill string.

The electric motor 558 may drive the hydraulic pump 552 by receivingelectricity from the microprocessor. The microprocessor may supply theelectricity at a first polarity to open the flapper 520 and at a secondreversed polarity to close the flapper 520. The position sensor 555 maybe able to detect when the piston is in the open position, the closedposition, or at any position between the open and closed positions sothat the microprocessor may detect full or partial opening of the valve.The position sensor 555 may be a Hall sensor and magnet or a linearvoltage differential transformer (LVDT). The position sensor 555 may bein electrical communication with the microprocessor via leads 554 s. Themicroprocessor may use the position sensor 555 to determine when thepiston shoulder 510 s has reached the open or closed position to shutoffthe motor 558 and close the valve 557. The antenna 526 may be bonded orfastened to an inner surface of the housing 505 and in electromagneticcommunication with the housing bore. The antenna 526 may be inelectrical communication with the microprocessor via leads 554 a. Theelectronics package 525, the motor 558, the pump 552, and the valve 557may be molded into a field replaceable unit and be fastened to a recessformed in an outer surface of the housing 505.

In operation, to open or close the valve 500, an RFID instruction tag,such as the passive tag 250 p may be pumped through the drill string1050 and exit the drill string 1050 via the drill bit 1050 b. The tag250 p may then be carried up the annulus 1025 until the tag is in rangeof the antenna 526. The microprocessor may read the command encoded inthe tag 250 p, such as to open the valve. The microprocessor may thenopen the valve 557 and operate the motor 558, thereby moving the pistonshoulder 510 s and the flow tube 515 into engagement with the flapper520. The microprocessor may then detect that the flapper 520 has opened.A verification RFID tag, such as the WISP tag 250 w, may then be pumpedthrough the drill string 1050 and return up the annulus 1025. The WISPtag 250 w may inquire about the position of the flapper 520 (asindirectly measured by the position sensor 555). The microprocessor maythen respond that the flapper 520 is open or respond with an errormessage if the actuator 550 malfunctioned and did not open the flapper520. The WISP tag 250 w may record the response and continue to the rig1000 where a surface reader may retrieve the information from the tag250 w. The error message may include the position of the piston shoulder510 s (the drilling operation may continue even if the flapper 520 isopen but not completely covered by the flow tube 515). Closing of theflapper may be similar to the opening operation. Additionally, the WISPtag 250 w may inquire and record a charge level of the battery.

Alternatively, instead of pumping tags to communicate with the isolationvalve 500, the telemetry sub 200 may be included in the drill string1050 and used to send the instruction signal to the valve microprocessorand receive the status information. The telemetry sub 200 may thencommunicate the status information to the rig 1000. Alternatively, thepiston 510 may be a mandrel having gear teeth formed along an outersurface thereof and the pump 552 may be replaced by a gear connectingthe motor 558 to the mandrel. Alternatively, instead of pumping tags tocommunicate with the isolation valve 500, the electronics package 525may include a vibration sensor in communication with the microprocessorand the instruction signal may be sent to the microprocessor by strikingthe casing according to a predetermined protocol. The striker may belocated at surface (i.e., in the wellhead) and operated by the rigcontroller.

FIG. 7A illustrates another way of operating the isolation valve 500,according to another embodiment of the present invention. Instead ofpumping the tags through the drill string 1050, two or more tags 601o,c, such as passive tags 250 p, may be embedded in an outer surface ofthe drill string 1050. The tags 601 o,c may be embedded in an outersurface of the drill bit 1050 b, a portion of the drill string 1050 nearthe drill bit, such as a drill collar, or a portion of the drill stringfarther away from the drill bit, such as the first joint of drill pipeconnected to the drill collar. The tags 601 o,c may spaced a sufficientdistance so that the tags are not simultaneously in range of the antenna526. The tag 601 o may be written with the open command and the tag 601c may be written with the close command. As the drill string 1050 islowered into range of the antenna 526, the microprocessor may read theclose command first from the tag 601 c and simply ignore the commandsince the microprocessor knows the valve 500 is already closed. Themicroprocessor may then read the open command from the tag 601 o andopen the valve 500. Conversely, when retrieving the drill string 1050from the wellbore 1005 (flapper 520 is open), the microprocessor mayread the open command first and ignore the command since themicroprocessor knows that the valve 500 is already open. Themicroprocessor may then read the closed command and close the flapper520 accordingly. If, as discussed below, the casing 1015 has beencemented with the flapper 520 open, the flapper may close when theactuator 550 receives the close command and then open when the actuatorreceives the open command.

Alternatively, each of the tags 601 o,c may be disposed in a fastener,such as a snap ring (not shown), fastened to an outer surface of thedrill string. Each snap ring may include a plurality of open 601 o orclose 601 c tags spaced therearound for redundancy. Each tag may bebonded in a recess formed in an outer surface of the snap ring, such asby epoxy. Each snap ring may be made from a hard material to resisterosion during drilling, such as tool steel, ceramic or cermet.Alternatively, an upper portion of the valve 500 including the actuator550 and the piston 510 may be a power sub split from a lower portion ofthe valve including the flapper and the flow tube by a spacer sub. Inthis alternative, the flow tube may include a piston shoulder incommunication with the piston. Alternatively, each of the tags 601 o,cmay instead be WISP tags 250 w and may record a position and/or statusof the battery of the valve to be read when the drill string isretrieved at the rig 1000.

FIG. 7B illustrates a charger 600 for use with an isolation valve 500 a,according to another embodiment of the present invention. FIG. 7C is anisometric view of the charger 600. In the event that the battery 531 ofthe actuator 550 becomes depleted, a charger 600 may be added to thedrill string 1050. The charger 600 may include a tubular housing 605having threaded couplings formed at each longitudinal end thereof forconnection with other components of the drill string 1050. The housing605 may include one or more sections (only one section shown) tofacilitate manufacturing and assembly, each section connected together,such as fastened with threaded connections. The housing 605 may have alongitudinal bore formed therethrough and one or more compartmentsformed in a wall thereof. An electronics package 625 (similar to theelectronics package 225) and a battery 631 may each be disposed in arespective compartment. The charger microprocessor and the battery 631may be in electrical communication via internal leads (not shown). Anantenna 626 (similar to the antenna 226 o) may be disposed around anouter surface of the charger housing 605.

The valve 500 a may be similar to the valve 500 except that an indicator560, such as a passive RFID tag 250 p, may be embedded in an innersurface of the valve housing 505 and a sleeve 565 may be added over thevalve antenna 526. The sleeve 565 may be fastened to the valve housing505, such as by a threaded connection. The sleeve 565 may be made froman electrically conductive, non-magnetic metal or alloy, such as acopper, copper alloy, aluminum, aluminum alloy, or stainless steel. Thesleeve 565 may be split into two poles by a dielectric material (notshown). The sleeve 565 may be in electrical communication with the valvemicroprocessor via leads (not shown). The indicator 560 may be locatednear the valve antenna 526.

One or more ribs 605 r may be formed in an outer surface of the housing605 and spaced therearound. A contact, such as a leaf spring 607, may befastened to the housing 605 and extend from each rib 605 r. Each contact607 may be in electrical communication with the charger microprocessorvia internal leads (not shown). In operation, the charger microprocessormay detect the indicator 560 and respond by supplying DC electricityfrom the battery 631 to two of the contacts 607. Opposite polarity maybe supplied to the other two contacts 607. The resulting current mayflow through the contacts 607 and the sleeve 565 to the valvemicroprocessor. The electricity may also charge the valve battery 531.The charger microprocessor and the valve microprocessor may alsocommunicate via the contacts 607 and the sleeve 565. The chargermicroprocessor may periodically query the valve microprocessor for abattery charge status and periodically query the indicator 560. Themicroprocessor may shutoff electricity when the valve battery 531 isfully charged or when the indicator 560 is out of range of the chargerantenna 626. During or after charging, a command RFID tag 250 p may bepumped through the drill string 1050 to open or close the flapper 520.

Alternatively, the contacts 607 may be replaced the antenna 626 thesleeve 565 may be omitted. The antenna 626 may be used to charge thevalve battery via inductive coupling between the antenna 626 and thevalve antenna 526 or a coil may be added to the valve for charging.Alternatively, a capacitor (not shown) may be used instead of thebattery 531. The capacitor may then be charged each time it is desiredto open or close the valve 500. The capacitor may also be used inaddition to the battery 531 as a backup in case the battery fails.Additionally, the charger 600 may include the mud pulser 275 forreporting to the drilling rig and/or the tachometer 255 and the pressuresensor 204 for receiving valve instruction signals from the drilling rigand relaying the signals to the isolation valve instead of pumping RFIDtags to send the signals.

FIG. 7D illustrates another charger 650 for use with an isolation valve500 b, according to another embodiment of the present invention. Thevalve 500 b may be similar to the valve 500 except that indicators 560u,

, such as passive RFID tags 250 p, may be embedded in an inner surfaceof the valve housing 505 and an inner surface of the piston 510. Thecharger 650 may include a tubular housing 655 having threaded couplingsformed at each longitudinal end thereof for connection with othercomponents of the drill string 1050. The housing 655 may include one ormore sections (only one section shown) to facilitate manufacturing andassembly, each section connected together, such as fastened withthreaded connections. The housing 655 may have a longitudinal boreformed therethrough and one or more compartments formed in a wallthereof. The electronics package 625 and the battery 631 may each bedisposed in respective compartments. The charger microprocessor and thebattery 631 may be in electrical communication via internal leads (notshown). The antenna 626 may be disposed around an outer surface of thecharger housing 605.

The charger 650 may be similar to the charger 600 except that instead ofthe contacts 607, the charger 650 may include one or more electromagnets660. The electromagnet 660 may be disposed in an outer compartmentformed in the housing 655 and include a winding. The winding 660 mayinclude wire or strap wound around an inner surface of the housing 655into a helical spiral and made of conductive material, such as aluminum,copper, aluminum alloy, or copper alloy. Each turn of the spiral may beelectrically isolated by a dielectric material, such as tape, or theconductive material may instead be anodized. The winding 660 may beisolated from the housing 655 by the dielectric material. The housing655 may be made from a ferromagnetic material, such as a metal or alloy,such as steel, to serve as a core of the electromagnet 660.Alternatively, the electromagnet 660 may include one or more toroidalwindings disposed in the housing compartment. Each toroidal winding mayinclude a winding wound around a core ring made from the ferromagneticmaterial and the housing may be made from the ferromagnetic material ora nonmagnetic material.

In operation, as the drill string 1050 is being longitudinally raised orlowered through the isolation valve 500 b, the charger microprocessormay read a respective indicator tag 560 u,

. The charger microprocessor may then supply DC electricity from thebattery 631 to the electromagnet 660. As the electromagnet 660 islongitudinally raised or lowered by the valve antenna 526, a DC voltage(electromotive force) may be generated in the antenna according toFaraday's law (analogous to a Faraday (shake charge) flashlight). Theresulting electricity may charge the valve battery 531. The chargermicroprocessor may continue to supply electricity to the electromagnet660 until the microprocessor detects the other indicator tag 560 u,

. The microprocessor may then shutoff the electricity to theelectromagnet 660 so that the electromagnet does not attract cuttingsduring drilling. The charger microprocessor may switch polarity suppliedto the electromagnet based on which indicator is detected first, therebyobviating need for the valve electronics 525 to include a rectifier. Astatus tag 250 w may then be circulated through the drill string 1050 toobtain a charge status of the valve battery. If a single pass of thedrill string 1050 is insufficient to charge the valve battery 531, thenthe drill string may be reciprocated in the valve 500 until the valvebattery is fully charged.

Alternatively, a plurality of chargers 650 may be distributed along thedrill string 1050 at regular intervals, such as one every thousand feetso that as the wellbore 1005 is being drilled or the drill string isbeing retrieved, the valve battery 531 intermittently receives a charge.

FIG. 7E illustrates another charger 575 for use with an isolation valve500 c, according to another embodiment of the present invention. FIG. 7Fis an enlargement of the charger 575. FIG. 7G is a cross-sectionillustrating two layers 587 of the charger 575. Except for the additionof the charger 575, the valve 500 c may be similar to the valve 500. Thecharger 575 may be a thermoelectric generator and may include asubstrate 580 made of thermally insulating dielectric such as, a ceramicwafer having a microporous structure, one face of which carries n-type585 n and p-type 585 p semiconductor elements.

The semiconductor elements 585 n,p may be placed alternately andconnected electrically in series to one another in order to formthermocouples 586 c,h at their junctions. Each element 585 n,p mayinclude a straight bar portion that extends transversely to thelongitudinal direction of the substrate 580 and two perpendicular barsopposing each other and located at respective ends of the straight barportion, thereby forming a Z-shaped element. Each element 585 n,p may bemade from a thin film of n-type doped or p-type doped polycrystallinesemiconductor ceramic. The junctions formed between the semiconductorelements 585 n,p may alternate from one side of the longitudinalmid-axis of the substrate 580 to the other, to form the respective hot586 h and cold 586 c junctions of the thermocouples. The materials ofthe substrate 580 and of the semiconductor elements 585 n,p may bechosen so as to have compatible thermal expansion coefficients so as toavoid high thermal stresses in the components of the generator 575during its use.

The generator 575 may include one or more layers 587 stacked in such away that the semiconductor elements 585 n,p carried by a substrate 580are covered by another substrate 580 of the same type and of the samesize. Each semiconductor element 585 n,p of each layer 587 may bethermally connected to the substrates 580 in parallel with the otherelements of the layer. Each layer 587 may be thermally connected inparallel with the other layers. The number of substrates 580 may be onegreater than that of the components, so that the semiconductor elementsof all the components are covered by a dielectric substrate 580. Thegenerator may include electrical connections, such as two connectingbands 590 (only one shown), made from electrically conductive material.Each band 590 may connect ends of cold junctions 586 c of the layerselectrically in either series or parallel and the internal leads mayconnect the bands to the microprocessor and/or battery 531. The thermalgenerator 575 may be bonded or fastened to an inner surface of thehousing 505 and connected to the microprocessor and/or battery viainternal leads (not shown).

In operation, an outer surface of the valve 500 c may be at an ambientwellbore temperature. To charge the battery 531, drilling fluid 1045 fhaving a temperature less or substantially less than the ambientwellbore temperature may be pumped through the drill string 1050 andinto the annulus 1025, thereby inducing a temperature gradient acrossthe generator 575. Due to the Peltier-Seebeck effect, a voltage may begenerated by the semiconductor elements 585 n,p, thereby charging thebattery 531. The temperature gradient between the drilling fluid 1045 fat ambient surface temperature and the wellbore temperature may besufficient to charge the battery 531.

FIGS. 8A-C illustrate another isolation assembly in the closed position,according to another embodiment of the present invention. The isolationassembly may include a power sub 700, the spacer sub 25, and theisolation valve 50. The isolation assembly may be assembled as part of acasing 1015 or liner string and run-into the wellbore 1005. The casing1015 or liner string may be cemented in the wellbore 1005 or be atie-back casing string.

The power sub 700 may include a tubular housing 705, a tubular mandrel710, and an actuator 750. The housing 705 may have couplings (not shown)formed at each longitudinal end thereof for connection with othercomponents of the casing/liner string. The couplings may be threaded,such as a box and a pin. The housing 705 may have a central longitudinalbore formed therethrough. Although shown as one piece, the housing 705may include two or more sections to facilitate manufacturing andassembly, each section connected together, such as fastened withthreaded connections.

The mandrel 710 may be disposed within the housing 705 andlongitudinally movable relative thereto between an upper position(shown) and a lower position. The mandrel 710 may have a lower profile711

formed in an inner surface thereof for receiving a cleat of a shiftingtool (not shown). The shifting tool may be similar to the shifting tool100 except that the actuator 150 may be omitted and a seat may be formedin an inner surface of the shifting tool mandrel for receiving ablocking member, such as a ball 1090 (FIG. 11A), deployed through thedrill string 1050 for operation thereof. The ball 1090 may be deployedby pumping or dropping. Although not shown, the mandrel 710 may furtherhave one or more position indicators similar to the indicators 15 p,

,h, discussed above. The mandrel 710 may further have a piston shoulder710 s formed in or fastened to an outer surface thereof. The pistonshoulder 710 s may be disposed in a chamber 706. The housing 705 mayfurther have upper 705 u and lower 705

shoulders formed in an inner surface thereof. The chamber 706 may bedefined radially between the mandrel 710 and the housing 705 andlongitudinally between an upper seal disposed between the housing 705and the mandrel 710 proximate the upper shoulder 705 u and a lower sealdisposed between the housing 705 and the mandrel 710 proximate the lowershoulder 705

. Hydraulic fluid may be disposed in the chamber 706. Each end of thechamber 706 may be in fluid communication with a respective hydrauliccoupling 709 c via a respective hydraulic passage 709 p formedlongitudinally through a wall of the housing 705.

The actuator 750 may include an antenna 726, an electronics package 725,a battery 731, a lock 752, a latch 754, a position sensor 755 and abiasing member, such as a coil spring 756. The antenna 726 andelectronics package 725 may be similar to the antenna 226 i and theelectronics package 225, respectively. The spring 756 may be disposed inthe chamber 706 against the upper shoulder 705 u and a top of theshoulder 710 s, thereby biasing the mandrel 710 toward the lowerposition where the valve 50 is open. The mandrel 710 may be selectivelyrestrained in the upper position (where the valve 50 is closed) by thelatch 754 and the lock 752. The latch 754 may be a collet connected tothe housing, such as being fastened. The collet may include a base ringand two or more radially split fingers. The mandrel 710 may have anupper profile 711 u formed in an outer surface thereof for receiving thefingers, thereby longitudinally connecting the mandrel 710 and thehousing 705. The fingers may be biased into engagement with the profile711 u. The spring bias may be sufficient to drive the collet fingersfrom the upper profile 711 u.

The lock 752 may include a linear actuator, such as a linear motor, anda sleeve longitudinally movable relative to the housing by the linearactuator between a locked position and an unlocked position. The sleevemay engage an outer surface of the collet fingers in the lockedposition, thereby keeping the fingers from radially moving out of theupper profile. The sleeve may be clear of the fingers in the unlockedposition, thereby allowing the collet fingers to radially move out ofthe upper profile. The linear actuator may be fastened to the housingand be in electrical communication with the electronics package 725 viainternal leads. The position sensor 755 may be a Hall sensor and magnetor a linear voltage differential transformer (LVDT). The position sensor755 may be in electrical communication with the microprocessor vialeads. The microprocessor may use the position sensor 755 to determinewhen the upper profile is aligned with the collet fingers to extend thesleeve and lock the collet fingers in the profile. The microprocessormay also use the position sensor to verify that the valve has opened.The antenna 726 may be bonded or fastened to an inner surface of thehousing 705 and in electromagnetic communication with the housing bore.The antenna 726 may be in electrical communication with themicroprocessor via leads.

In operation, to open the valve 50, an RFID instruction tag, such as thepassive tag 250 p may be pumped through the drill string 1050 and exitthe drill string via the drill bit 1050 b. The tag 250 p may then becarried up the annulus 1025 until the tag is in range of the antenna726. The microprocessor may read the command encoded in the tag 250 p,such as to open the valve. The microprocessor may move the sleeve to theunlocked position by supplying electricity to the linear actuator,thereby allowing the spring 756 to move the piston shoulder 710 slongitudinally downward and open the valve 50. Movement of the pistonshoulder 710 s may be damped by a damper, such as an orifice 740,disposed in the passage 709 p. The microprocessor may then detect thatthe valve 50 has opened. A verification RFID tag, such as the WISP tag250 w, may then be pumped through the drill string 1050 and return upthe annulus 1025. The WISP tag 250 w may inquire about the position ofthe valve 50. The microprocessor may then respond that the flapper 70 isopen or respond with an error message if the actuator 750 malfunctionedand did not open the valve 50. The WISP tag 250 w may record theresponse and continue to the rig 1000 where a surface reader mayretrieve the information from the tag 250 w. The error message mayinclude the position of the piston shoulder 710 s (the drillingoperation may continue even if the flapper 70 is open but not completelycovered by the flow tube 60). Additionally, the WISP tag 250 w mayinquire and record a charge level of the battery.

To close the valve 50 after a drilling operation, the drill string 1050may raised until the shifting tool cleat is aligned or nearly alignedwith the lower profile 711

. An RFID instruction tag, such as the passive tag 250 p, may be pumpedthrough the drill string 1050 and exit the drill string via the drillbit 1050 b. The tag 250 p may then be carried up the annulus 1025 untilthe tag is in range of the antenna 726. The microprocessor may read thecommand encoded in the tag 250 p, such as to close the valve 50. Themicroprocessor may supply electricity to the linear actuator, therebyunlocking the sleeve. The ball 1090 may then be launched from the rig1000 and pumped down through the drill string 1050 until the ball landson the shifting tool seat. Continued pumping may exert fluid pressure onthe ball 1090, thereby driving the shifting tool mandrel longitudinallydownward and moving the shifting tool inner slips relative to the outerslips. Once the ball 1090 has landed and the slips have operated,pumping may be halted and pressure maintained. The shifting toolfasteners may be wedged outward by the relative longitudinal movement ofthe slips. The shifting tool fasteners may push the cleat intoengagement with an inner surface of the mandrel 710. If the cleat ismisaligned with the lower profile 711

, then the shifting tool may be raised and/or lowered until the cleat isaligned with the profile. The shifting tool leaf spring may allow thecleat to be pushed inward by the profile during engagement of theprofile with the cleat. Engagement of the cleat with the profile 711

may longitudinally connect the shifting tool and the mandrel 710. Theshifting tool may be raised thereby raising the mandrel 710 against thespring 756 until the collet fingers are aligned with and engage theprofile 711 u. The microprocessor may detect engagement using theposition sensor and shutoff electricity to the microprocessor, therebylocking the sleeve.

Alternatively, the embedded tags 601 o,c may be used to send the openand/or closed commands. Additionally, any of the chargers 600, 650, 575may be used to charge the battery 731 and a capacitor may be usedinstead of or in addition to the battery as discussed above.

FIGS. 9A-C illustrate another isolation assembly in the closed position,according to another embodiment of the present invention. The isolationassembly may include a power sub 800, the spacer sub 25, and theisolation valve 50. The isolation assembly may be assembled as part of acasing 1015 or liner string and run-into the wellbore 1005. The casing1015 or liner string may be cemented in the wellbore 1005 or be atie-back casing string.

The power sub 800 may include a tubular housing 805, hydraulic pump, andan actuator 850. The housing 805 may have couplings (not shown) formedat each longitudinal end thereof for connection with other components ofthe casing/liner string. The couplings may be threaded, such as a boxand a pin. The housing 805 may have a central longitudinal bore formedtherethrough. Although shown as one piece, the housing 805 may includetwo or more sections to facilitate manufacturing and assembly, eachsection connected together, such as fastened with threaded connections.The housing 805 may have a piston chamber 805 c, an accumulator chamber820 a, and a reservoir chamber 820 r formed therein and one or moreports 805 p providing fluid communication between the housing bore andthe piston chamber 805 c. Hydraulic fluid may be disposed in thechambers 805 c, 820 a,r. The housing may further have hydraulic passages809 u,

formed there through providing fluid communication between the actuatorand respective hydraulic couplings 809 c. The hydraulic couplings 809 cmay be connected to respective hydraulic couplings of the spacer sub 29c. The passage 809 u may provide fluid communication between theactuator 850 and an upper portion of the valve chamber 57 and thepassage 809

may provide fluid communication between the actuator and a lower portionof the valve chamber (via the spacer sub 25 and respective passages 59p).

The hydraulic pump may include the piston chamber 805 c, piston 810, andcheck valves 815 a,r, and a biasing member, such as a coil spring 830.Alternatively, the hydraulic pump may include a diaphragm instead of thepiston 810. The piston 810 may be disposed in the piston chamber 805 cand carry a seal on inner and outer surfaces thereof for engaging thepiston chamber wall. The piston 810 may divide the piston chamber 805 cinto upper and lower portions. The spring 830 may be disposed in thepiston chamber lower portion and may bias the piston toward the ports805 p. The hydraulic fluid may be disposed in the lower portion of thepiston chamber 805 c.

The upper piston chamber portion may be in fluid communication with thehousing bore via the ports 805 p and the lower portion may be incommunication with the check valve 815 a via a hydraulic passage 808 aformed longitudinally through a wall of the housing 805. The passage 808a may also provide fluid communication between the check valve 815 a andthe accumulator chamber 820 a and between the accumulator chamber andthe actuator 850. The check valve 815 a may be operable to allowhydraulic fluid flow therethrough from the piston chamber lower portionto the accumulator chamber 820 a and prevent reverse flow therethrough.The lower piston chamber portion may also be in communication with acheck valve 815 r via a hydraulic passage 808 r formed longitudinallythrough a wall of the housing 805. The passage 808 r may also providefluid communication between the check valve 815 r and the reservoirchamber 820 r and between the reservoir chamber and the actuator 850.The check valve 815 r may be operable to allow hydraulic fluid flowtherethrough from the reservoir chamber 820 r to the piston chamberlower portion and prevent reverse flow therethrough.

Each of the accumulator 820 a and reservoir 802 r chambers may include adivider, such as a floating piston, bellows, or diaphragm, dividing eachchamber into a gas portion and a hydraulic portion. A gas, such asnitrogen, may be disposed in the gas portion and hydraulic fluid may bedisposed in the hydraulic portion.

In operation, the hydraulic pump may utilize fluctuations in the housing(casing) bore to pressurize the accumulator chamber 820 a. For example,as drilling fluid 1045 f is circulated for drilling the wellbore 1005,friction due to the returns 1045 r flowing up the annulus 1025 and/oruse of the choke 1065 may substantially increase the pressure in thebore as compared to hydrostatic pressure. Pressure in the bore may causelongitudinal movement of the piston 810 downward against the spring 830,thereby forcing hydraulic fluid through the check valve 815 a into theaccumulator 820 a. Once pressure in the bore is reduced, the spring 830may reset the piston 810. As the piston 810 travels longitudinallyupwardly in the bore, the piston may draw hydraulic fluid from thereservoir 820 r through the check valve 815 r. The accumulator chamber820 a may store the fluid energy until it is time to open or close thevalve 50. The accumulator 820 a may store sufficient fluid energy forone or more strokes of the valve 50.

FIGS. 9D and 9E illustrate operation of the actuator 850. The actuator850 may include an antenna 826 (FIG. 8A), an electronics package 825, abattery 831, an electric motor 852, a gearbox 854, and one or morethree-way valves 855 a,r. The antenna 826 and electronics package 825may be similar to the antenna 226 i and the electronics package 225,respectively. Each of the three-way valves 855 a,r may be in fluidcommunication with the passages 808 a,r, the accumulator chamber 820 a,and the reservoir chamber 820 r via hydraulic passages formed in a wallof the housing 805. The gear box 854 may include a drive gearrotationally connected to the motor 852 and a valve gear engaged withthe drive gear and connected to each of the three-way valves 855 a,r.The gearbox 854 may convert rotation of the motor 852 about a first axisinto rotation of each of the valves about a second axis.

In operation, to open the isolation valve 50, an RFID instruction tag,such as the passive tag 250 p may be pumped through the drill string1050 and exit the drill string via the drill bit 1050 b. The tag 250 pmay then be carried up the annulus 1025 until the tag 250 p is in rangeof the antenna. The microprocessor may read the command encoded in thetag 250 p, such as to open the valve 50. The microprocessor may supplyelectricity to the motor 852 at a first polarity. The motor 852 mayrotate the valves 855 a,r (via the gearbox) from the position in FIG. 9Eto the position in FIG. 9D. The motor 852 may include a rotor positionsensor in communication with the microprocessor to indicate when themotor has fully rotated the valves 855 a,r. The microprocessor may thenshutoff electricity to the motor when the valves have reached theposition illustrated in FIG. 9D. The accumulator chamber 820 a may thensupply pressurized hydraulic fluid to the piston shoulder 61 via passage809 u, thereby moving the flow tube 60 downward into engagement with theflapper 70. Return fluid may flow from the valve chamber 57 to theaccumulator 820 a via passage 809

. Once the isolation valve 50 is open, the three way valves 855 a,r maybe left in the position of FIG. 9D until the microprocessor receives aclose command.

In operation, to close the isolation valve 50, an RFID instruction tag,such as the passive tag 250 p may be pumped through the drill string1050 and exit the drill string via the drill bit 1050 b. The tag 250 pmay then be carried up the annulus 1025 until the tag is in range of theantenna 826. The microprocessor may read the command encoded in the tag250 p, such as to close the valve. The microprocessor may supplyelectricity to the motor 852 at a second polarity opposite to the firstpolarity. The motor 852 may rotate the valves (via the gearbox) from theposition in FIG. 9D to the position in FIG. 9E. The microprocessor maythen shutoff electricity to the motor 852 when the valves 855 a,r havereached the position illustrated in FIG. 9E. The accumulator chamber 820a may then supply pressurized hydraulic fluid to the piston shoulder 61via passage 809

, thereby moving the flow tube 60 upward out of engagement with theflapper 70. Return fluid may flow from the valve chamber 57 to theaccumulator via passage 809 u. Once the isolation valve 50 is open, thethree way valves 855 a,r may be left in the position of FIG. 9E untilthe microprocessor receives an open command.

Additionally, the actuator may include a flow meter (not shown) disposedin one or both of the passages 809 u,l and in electrical communicationwith the microprocessor to serve as a position indicator. Theverification RFID tag, such as the WISP tag 250 w, may then be pumpedthrough the drill string 1050 and return up the annulus 1025 after thevalve 50 has been closed or opened to verify the position of the valve.Alternatively, the embedded tags 601 o,c may be used to send the openand/or closed commands. Additionally, any of the chargers 605, 650, 575may be used to charge the battery 831 and a capacitor may be usedinstead of or in addition to the battery as discussed above.Alternatively, the spacer sub 25 may be omitted and the power sub 800may be incorporated into the isolation valve 50.

FIG. 10A illustrates a portion of another isolation valve 900 a in theclosed position, respectively, according to another embodiment of thepresent invention. The isolation valve 900 a may be used in theisolation assembly of FIGS. 1A-C to replace a lower portion (FIG. 10) ofthe isolation valve 50.

The isolation valve 900 a may include a tubular housing 905 a, a flowtube 910, and a closure member, such as the flapper 920. As discussedabove, the closure member may be a ball (not shown) instead of theflapper 920. To facilitate manufacturing and assembly, the housing 905may include one or more sections 905 a-d each connected together, suchas fastened with threaded connections and/or fasteners. The housing 905may further include a lower adapter (not shown) connected to the section905 b for connection with casing or liner. The housing 905 may have alongitudinal bore formed therethrough for passage of a drill string. Theflow tube 910 may be disposed within the housing 905. The flow tube 910may be longitudinally movable relative to the housing 905.

The flow tube 910 may be longitudinally movable by the piston betweenthe open position and the closed position. In the closed position, theflow tube 910 may be clear from the flapper 920, thereby allowing theflapper 920 to close. In the open position, the flow tube 910 may engagethe flapper 920, push the flapper 920 to the open position, and engage aseat 906 s formed in and/or fastened to a bottom of the housing section905 c. Engagement of the flow tube 910 with the seat 906 s may form achamber 906 between the flow tube 910 and the housing 905, therebyprotecting the flapper 920 and the flapper seat 906 s. The flapper 920may be pivoted to the housing 905, such as by a fastener 920 p. Abiasing member, such as a torsion spring 921, may engage the flapper 920and the housing 905 and be disposed about the fastener 920 p to bias theflapper 920 toward the closed position. In the closed position, theflapper 920 may fluidly isolate an upper portion of the valve from alower portion of the valve.

The valve 900 a may further include one or more sensors, such as anupper pressure sensor 904 u, a lower pressure sensor 904

, a flow tube position sensor 912 t, and a flapper proximity sensor 904f. The valve 900 a may further include an electronics package 925, anantenna 926, and a battery 931. The antenna 926 and electronics package925 may be similar to the antenna 226 i and the electronics package 225,respectively. The flow tube 910 may be made from a non-magnetic metal oralloy, such as stainless steel so as to not obstruct antenna reception.The upper pressure sensor 904 u may be in fluid communication with thehousing bore above the flapper 920 and the lower pressure sensor 904

may be in fluid communication with the housing bore below the flapper.The flow tube 910 may allow leakage thereby so as to not fluidly isolatethe pressure sensors 904 u,

. The pressure sensors 904 u,

may also be operable to measure temperature. Lead wires 909 a mayprovide electrical communication between the microprocessor and thesensors 904 u,

, 912 f,t. The position sensor 912 t and proximity sensor 912 f may eachbe a Hall sensor and magnet or the position sensor may be a linearvoltage differential transformer (LVDT). Alternatively, the proximitysensor 912 f may be a contact switch. The flow tube position sensor 912t may be able to detect when the flow tube 910 is in the open position,the closed position, or at any position between the open and closedpositions so that the microprocessor may detect full or partial openingof the valve. The flapper proximity sensor 912 f may detect closure ofthe flapper. The flapper sensor 912 f may be in electrical communicationwith the leads 909 a via contacts 913.

In operation, instead of using the position indicator 15

to verify opening or closing of the valve, a verification tag, such asthe WISP tag 250 w may be pumped through the drill string and return upthe annulus. The valve microprocessor may read the position inquirycommand encoded in the WISP tag 250 w and report the position of thevalve 50 using the position sensors 912 t,f. The WISP tag 250 w mayrecord the response and continue up to the telemetry sub 200. Thetelemetry microprocessor may read the position from the tag 250 w andreport to the rig 1000. The WISP tag may also inquire about pressure andtemperature above and/or below the flapper, record the pressure andtemperature, and report the pressure and temperature to the telemetrymicroprocessor.

Alternatively, instead of pumping the WISP tag 250 w, the drill stringmay include one or more embedded WISP tags 250 w similar to the tag 601c. The tag may then be read when the drill string 1050 is retrieved tothe rig 1000. Alternatively, the antenna 926 may be located in the powersub 1 and the leads 909 a may extend from the valve 900 a to the powersub so that the antenna 926 may be used to communicate with thetelemetry sub.

FIGS. 10B illustrates a portion of another isolation valve 900 b in theclosed position, respectively, according to another embodiment of thepresent invention. The isolation valve 900 b may replace a lower portion(FIG. 6B) of any of the isolation valves 500, 500 a, 500 b. Theisolation valve 900 b may also be used in the isolation assembly ofFIGS. 8A-C or 9A-C to replace a lower portion (FIG. 8C or 9C) of theisolation valve 50. The isolation valve 900 b may be similar to theisolation valve 900 a except that the antenna, electronics package, andbattery may be omitted in favor of extending the leads 909 b to theexisting electronics packages 525, 725, 825 of the respective valves orpower subs. In this manner, the position and pressures may be reportedas discussed above. Alternatively, the pressure sensor 904 u may be usedto receive pressure pulses sent from the drilling rig to carry theinstruction signals instead of the RFID tag. Additionally, the pressuresignals and the RFID tag may be used to send the signals and the valve909 b may not execute the command until receiving both signals.

Alternatively, the isolation valve 400 may replace a lower portion (FIG.6B) of any of the isolation valves 500, 500 a, 500 b. The isolationvalve 900 b may also be used in the isolation assembly of FIGS. 8A-C or9A-C to replace a lower portion (FIG. 8C or 9C) of the isolation valve50.

FIG. 11A illustrates a drilling rig 1000 for drilling a wellbore 1005,according to another embodiment of the present invention. The drillingrig 1000 may be deployed on land or offshore. If the wellbore 1005 issubsea, then the drilling rig 1000 may be a mobile offshore drillingunit, such as a drillship or semisubmersible. The drilling rig 1000 mayinclude a derrick 1004. The drilling rig 1000 may further includedrawworks 1024 for supporting a top drive 1006. The top drive 1006 mayin turn support and rotate a drill string 1050. Alternatively, a Kellyand rotary table (not shown) may be used to rotate the drill stringinstead of the top drive. The drilling rig 1000 may further include arig pump 1018 operable to pump drilling fluid 1045 f from of a pit ortank 1008, through a standpipe and Kelly hose to the top drive 1006. Thedrilling fluid 1045 f may include a base liquid. The base liquid may berefined oil, water, brine, or a water/oil emulsion. The drilling fluid1045 f may further include solids dissolved or suspended in the baseliquid, such as organophilic clay, lignite, and/or asphalt, therebyforming a mud. The drilling fluid 1045 f may further include a gas, suchas diatomic nitrogen mixed with the base liquid, thereby forming atwo-phase mixture. If the drilling fluid is two-phase, the drilling rig1000 may further include a nitrogen production unit (not shown) operableto produce commercially pure nitrogen from air.

The drilling rig 1000 may further include a launcher 1002, programmablelogic controller (PLC) 1070, and a pressure sensor 1028. The pressuresensor 1028 may detect mud pulses sent from the telemetry sub 200. ThePLC 1070 may be in data communication with the rig pump 1018, launcher1002, pressure sensor 1028, and top drive 1006. The rig pump 1018 and/ortop drive 1006 may include a variable speed drive so that the PLC 1070may modulate 1095 a flow rate of the rig pump 1018 and/or an angularspeed (RPM) of the top drive 1006. The modulation 1045 may be a squarewave, trapezoidal wave, or sinusoidal wave. Alternatively, the PLC 1070may modulate the rig pump and/or top drive by simply switching them onand off.

FIGS. 11B-11I illustrate a method of drilling and completing a wellboreusing the drilling rig 1000. An upper section of a wellbore 1005 througha non-productive formation 1030 n has been drilled using the drillingrig 1000. A casing string 1015 has been installed in the wellbore 1005and cemented 1010 in place. One of the isolation valve/assembliesdiscussed and illustrated above has been assembled as part of the casingstring 1015 and is represented by the depiction of a flapper 1020.Alternatively, as discussed above, the isolation valve/assembly mayinstead be assembled as part of a tie-back casing string received by apolished bore receptacle of a liner string cemented to the wellbore. Theisolation valve 1020 may be in the open position for deployment andcementing of the casing string. Once the casing string 1015 has beendeployed and cemented, a drill string 1050 may be deployed into thewellbore for drilling of a productive hydrocarbon bearing (i.e., crudeoil and/or natural gas) formation 1030 p.

The drilling fluid 1045 f may flow from the standpipe and into the drillstring 1050 via a swivel (Kelly or top drive, not shown). The drillingfluid 1045 f may be pumped down through the drill string 1050 and exit adrill bit 1050 b, where the fluid may circulate the cuttings away fromthe bit 1050 b and return the cuttings up an annulus 1025 formed betweenan inner surface of the casing 1015 or wellbore 1005 and an outersurface of the drill string 1050. The return mixture (returns) 1045 rmay return to a surface 1035 of the earth and be diverted through anoutlet 1060 o of a rotating control device (RCD) 1060 and into a primaryreturns line (not shown). The returns 1045 r may then be processed byone or more separators (not shown). The separators may include a shaleshaker to separate cuttings from the returns and one or more fluidseparators to separate the returns into gas and liquid and the liquidinto water and oil.

The RCD 1060 may provide an annular seal 1060 s around the drill string1050 during drilling and while adding or removing (i.e., during atripping operation to change a worn bit) segments or stands to/from thedrill string 1050. The RCD 1060 achieves fluid isolation by packing offaround the drill string 1050. The RCD 1060 may include apressure-containing housing mounted on the wellhead where one or morepacker elements 1060 s are supported between bearings and isolated bymechanical seals. The RCD 1060 may be the active type or the passivetype. The active type RCD uses external hydraulic pressure to activatethe packer elements 1060 s. The sealing pressure is normally increasedas the annulus pressure increases. The passive type RCD uses amechanical seal with the sealing action supplemented by wellborepressure. If the drillstring 1050 is coiled tubing or other non-jointedtubular, a stripper or pack-off elements (not shown) may be used insteadof the RCD 1060. One or more blowout preventers (BOPs) 1055 may beattached to the wellhead 1040.

A variable choke valve 1065 may be disposed in the returns line. Thechoke 1065 may be in communication with a programmable logic controller(PLC) 1070 and fortified to operate in an environment where the returns1045 r contain substantial drill cuttings and other solids. The choke1065 may be employed during normal drilling to exert back pressure onthe annulus 1025 to control bottom hole pressure exerted by the returnson the productive formation. The drilling rig 1000 may further include aflow meter (not shown) in communication with the returns line to measurea flow rate of the returns and output the measurement to the PLC 1070.The flow meter may be single or multi-phase. Alternatively, a flow meterin communication with the PLC 1070 may be in each outlet of theseparators to measure the separated phases independently.

The PLC 1070 may further be in communication with the rig pump toreceive a measurement of a flow rate of the drilling fluid injected intothe drill string. In this manner, the PLC may perform a mass balancebetween the drilling fluid 1045 f and the returns 1045 r to monitor forformation fluid 1090 entering the annulus 1025 or drilling fluid 1045 fentering the formation 1030 p. The PLC 1070 may then compare themeasurements to calculated values by the PLC 1070. If nitrogen is beingused as part of the drilling fluid, then the flow rate of the nitrogenmay be communicated to the PLC 1070 via a flow meter in communicationwith the nitrogen production unit or a flow rate measured by a boostercompressor in communication with the nitrogen production unit. If thevalues exceed threshold values, the PLC 1070 may take remedial action byadjusting the choke 1065. A first pressure sensor (not shown) may bedisposed in the standpipe, a second pressure sensor (not shown) may bedisposed between the RCD outlet 1060 o and the choke 1065, and a thirdpressure sensor (not shown) may be disposed in the returns linedownstream of the choke 1065. The pressure sensors may be in datacommunication with the PLC.

The drill string 1050 may include the drill bit 1050 b disposed on alongitudinal end thereof, one of the shifting tools discussed above(depicted by 1050 s), and a string of drill pipe 1050 p. Alternatively,casing, liner, or coiled tubing may be used instead of the drill pipe1050 p. The drill string 1050 may also include a bottom hole assembly(BHA) (not shown) that may include the bit 1050 b, drill collars, a mudmotor, a bent sub, measurement while drilling (MWD) sensors, loggingwhile drilling (LWD) sensors and/or a float valve (to prevent backflowof fluid from the annulus). The mud motor may be a positive displacementtype (i.e., a Moineau motor) or a turbomachine type (i.e., a mudturbine). The drill string 1050 may further include float valvesdistributed therealong, such as one in every thirty joints or tenstands, to maintain backpressure on the returns while adding jointsthereto. The drill string 1050 may also include one or more centralizers1050 c (FIG. 14D) spaced therealong at regular intervals. The drill bit1050 b may be rotated from the surface by the rotary table or top driveand/or downhole by the mud motor. If a bent sub and mud motor isincluded in the BHA, slide drilling may be effected by only the mudmotor rotating the drill bit and rotary or straight drilling may beeffected by rotating the drill string from the surface slowly while themud motor rotates the drill bit. Alternatively, if coiled tubing is usedinstead of drill pipe, the BHA may include an orienter to switch betweenrotary and slide drilling. If the drill string 1050 is casing or liner,the liner or casing may be suspended in the wellbore 1005 and cementedafter drilling.

The drill string 1050 may be operated to drill through the casing shoe1015 s and then to extend the wellbore 1005 by drilling into theproductive formation 1030 p. A density of the drilling fluid 1045 f maybe less than or substantially less than a pore pressure gradient of theproductive formation 1030 p. A free flowing (non-choked) equivalentcirculation density (ECD) of the returns 1045 r may also be less than orsubstantially less than the pore pressure gradient. During drilling, thevariable choke 1065 may be controlled by the PLC 1070 to maintain theECD to be equal to (managed pressure) or less than (underbalanced) thepore pressure gradient of the productive formation 1030 p. If, duringdrilling of the productive formation, the drill bit 1050 b needs to bereplaced or after total depth is reached, the drill string 1050 may beremoved from the wellbore 1005. The drill string 1050 may be raiseduntil the drill bit 1050 b is above the flapper 1020 and the shiftingtool 1050 s is aligned with the power sub. The shifting tool 1050 s maythen be operated to engage the power sub (or one of the power subs) toclose the flapper 1020. Alternatively, as discussed above, the shiftingtool 1050 s may be omitted for some of the embodiments (i.e., the valve500) and an instruction signal may be sent to the valve 1020.

The drill string 1050 may then be further raised until the BHA/drill bit1050 b is proximate the wellhead 1040. An upper portion of the wellbore1005 (above the flapper 1020) may then be vented to atmosphericpressure. The returns 1045 r may also be displaced from the upperportion of the wellbore using air or nitrogen. The RCD 1060 may then beopened or removed so that the drill bit/BHA 1050 b may be removed fromthe wellbore 1005. If total depth has not been reached, the drill bit1050 b may be replaced and the drill string 1050 may be reinstalled inthe wellbore. The annulus 1025 may be filled with drilling fluid 1045 f,pressure in the upper portion of the wellbore 1005 may be equalized withpressure in the lower portion of the wellbore 1005. The shifting tool1050 s may be operated to engage the power sub and open the flapper1020. Drilling may then resume. In this manner, the productive formation1030 p may remain live during tripping due to isolation from the upperportion of the wellbore by the closed flapper 1020, thereby obviatingthe need to kill the productive formation 1030 p.

Once drilling has reached total depth, the drill string 1050 may beretrieved to the drilling rig as discussed above. A liner string, suchas an expandable liner string 1075

, may then be deployed into the wellbore 1005 using a workstring 1075.The workstring 1075 may include an expander 1075 e, the shifting tool1050 s, a packer 1075 p and the string of drill pipe 1050 p. Theexpandable liner 1075

may be constructed from one or more layers, such as three. The threelayers may include a slotted structural base pipe, a layer of filtermedia, and an outer shroud. Both the base pipe and the outer shroud maybe configured to permit hydrocarbons to flow through perforations formedtherein. The filter material may be held between the base pipe and theouter shroud and may serve to filter sand and other particulates fromentering the liner 1075

. The liner string 1075

and workstring 1050 s may be deployed into the live wellbore using theisolation valve 1020, as discussed above for the drill string 1050.

Once deployed, the expander 1075 e may be operated to expand the liner1075

into engagement with a lower portion of the wellbore traversing theproductive formation 1030 p. Once the liner 1075

has been expanded, the packer 1070 s may be set against the casing 1015.The packer 1075 p may include a removable plug set in a housing thereof,thereby isolating the productive formation 1030 p from the upper portionof the wellbore 1005. The packer housing may have a shoulder forreceiving a production tubing string 1080. Once the packer is set, theexpander 1075 e, the shifting tool 1050 s, and the drill pipe 1050 p maybe retrieved from the wellbore using the isolation valve 1020 asdiscussed above for the drill string 1050.

Alternatively, a conventional solid liner may be deployed and cementedto the productive formation 1030 p and then perforated to provide fluidcommunication. Alternatively, a perforated liner (and/or sandscreen) andgravel pack may be installed or the productive formation 1030 p may beleft exposed (a.k.a. barefoot).

The RCD 1060 and BOP 1055 may be removed from the wellhead 1040. Aproduction (aka Christmas) tree 1085 may then be installed on thewellhead 1040. The production tree 1085 may include a body 1085 b, atubing hanger 1085 h, a production choke 1085 v, and a cap 1085 c and/orplug. Alternatively, the production tree 1085 may be installed after theproduction tubing 1080 is hung from the wellhead 1040. The productiontubing 1080 may then be deployed and may seat in the packer body. Thepacker plug may then be removed, such as by using a wireline orslickline and a lubricator. The tree cap 1085 c and/or plug may then beinstalled. Hydrocarbons 1090 produced from the formation 1030 p mayenter a bore of the liner 1075

, travel through the liner bore, and enter a bore of the productiontubing 1080 for transport to the surface 1035.

FIG. 12A illustrates a portion of a power sub 1100 for use with theisolation assembly in a retracted position, according to anotherembodiment of the present invention. FIG. 12B illustrates a portion ofthe power sub 1100 in an extended position.

The power sub 1100 may include a tubular housing 1105, a tubular mandrel1110, a sleeve 1125, an actuator 1150, a piston (not shown, see 315),and a driver (not shown). The housing 1105 may have couplings (notshown) formed at each longitudinal end thereof for connection with othercomponents of the casing/liner string. The couplings may be threaded,such as a box and a pin. The housing 1105 may have a centrallongitudinal bore formed therethrough. Although shown as one piece, thehousing 1105 may include two or more sections to facilitatemanufacturing and assembly, each section connected together, such asfastened with threaded connections. The power sub 1100 may be operatedby a shifting tool 1175 assembled as part of the drill string 1050instead of the shifting tool 1050 s.

The mandrel 1110 may be disposed within the housing 1105, longitudinallyconnected thereto, and rotatable relative thereto. The mandrel 1110 mayinclude an upper drive portion 1110 c,f,

and a lower sleeve portion 1110 s connected by a base portion 1110 b.The drive portion may include a plurality of split collet fingers 1110 fextending longitudinally from the (solid) base 1110 b. The fingers 1110f may have lugs 1110

formed at an end distal from the base 1110 b. The fingers 1110 f may beoperated between the retracted position and the extended position byinteraction with the sleeve 1125. The sleeve 1125 may include an uppersleeve portion 1125 u and a lower sleeve portion 1125

connected by a shoulder portion 1125 s. The fingers 1110 f may furtherinclude cams 1110 c formed in an outer surface thereof. Each cam 1110 cmay be received by a follower, such as a slot 1125 f, when the fingersare in the retracted position. Each slot 1125 f may be formed through awall of the lower sleeve portion 1125

and a periphery thereof may have an inclined surface for mating with acorresponding inclined surface of the cam 1110 c during movement of thefingers 1110 f from the retracted position to the extended position. Thefingers 1110 f may be naturally biased toward the retracted position.

The lugs 1110

may mate with a torque profile when the power sub 1100 is in theextended position. The torque profile may include a plurality of ribs1175 r, spaced around and extending along an outer surface of a body1175 b of the shifting tool 1175, thereby rotationally connecting theshifting tool and the mandrel 1110 while allowing relative longitudinalmovement therebetween. The ribs 1175 r may have a length substantiallygreater than a length of the lugs 1110

to provide an engagement tolerance and/or to compensate for heave of thedrill string 1050 for subsea drilling operations. The mandrel 1110 mayfurther have a helical profile (not shown) formed in an outer surface ofthe sleeve portion 1110 s.

The actuator 1150 may include an antenna 1126, an electronics package1125, a battery 1131, a case 1151, a lock 1152, 1153, a latch 1154, aproximity sensor 1155 (or position sensor, see 755) and a biasingmember, such as a coil spring 1130. The antenna 1126 and electronicspackage 1125 may be similar to the antenna 226 i and the electronicspackage 225, respectively. The housing 1105 may further have upper 1107u and lower (not shown) shoulders formed in an inner surface thereof.The chamber 1107 may be defined longitudinally between an upper sealdisposed between the housing 1105 and the case 1151 proximate the uppershoulder 1107 u and lower seals disposed between the housing 1105 andthe driver and between the mandrel 1110 and the driver proximate thelower shoulder. Lubricant may be disposed in an isolated portion of thechamber 1107. A compensator piston (not shown) may be disposed in thehousing 1105 to compensate for displacement of lubricant due to movementof the driver and/or sleeve 1125. The compensator piston may also serveto equalize pressure of the lubricant (or slightly increase) withpressure in the housing bore.

The case 1151 may be tubular and have upper 1151 u and lower 1151

shoulders formed in an inner surface thereof. The case 1151 may belongitudinally connected to the housing 1105. The spring 1130 may bedisposed in a sub-chamber against a bottom of the lower shoulder 1151

and a top of the shoulder 1125 s, thereby biasing the sleeve 1125 towarda lower position where the fingers 1110 f are extended. The sleeve 1125may be selectively restrained in an upper position (where the fingers1110 f are retracted) by the latch 1154 and the lock 1152, 1153. Thelatch may be a collet 1154 connected to the case 1151, such as beingfastened. The collet 1154 may include a base ring and two or moreradially split fingers. The upper sleeve portion 1125 u may have aprofile 1125 g formed in an outer surface thereof for receiving thecollet 1154, thereby longitudinally connecting the sleeve 1125 and thecase 1151. The collet 1154 may be naturally biased into engagement withthe profile 1125 g. The spring bias may be sufficient to drive thecollet 1154 from the profile 1125 g.

The lock may include a linear actuator 1152, such as a linear motor, anda sleeve 1153 longitudinally movable relative to the housing by thelinear actuator between a locked position and an unlocked position. Thesleeve 1153 may engage an outer surface of the collet fingers in thelocked position, thereby keeping the fingers from radially moving out ofthe profile 1125 g. The sleeve 1153 may be clear of the fingers in theunlocked position, thereby allowing the collet fingers to radially moveout of the profile 1125 g. The linear actuator 1152 may be fastened tothe case 1151 and be in electrical communication with the electronicspackage 1125 via internal leads. The proximity sensor 1155 may be acontact switch or Hall sensor and magnet operable to detectproximity/contact between a top of the sleeve 1125 and the shoulder 1151u and may be in electrical communication with the microprocessor vialeads. The microprocessor may use the proximity sensor 1155 to determinewhen the profile 1125 g is aligned with the collet fingers to extend thelock sleeve 1153 and lock the collet fingers in the profile. Themicroprocessor may also use the proximity sensor to verify that thevalve has opened or closed. The antenna 1126 may be bonded or fastenedto an inner surface of the case 1151 and in electromagneticcommunication with the housing bore. The antenna 1126 may be inelectrical communication with the microprocessor via leads.

The piston may be tubular and have a shoulder disposed in a pistonchamber (not shown, see 306) formed in the housing 1105. The housing1105 may further have upper and lower shoulders (not shown, see 306 u,

) formed in an inner surface thereof. The piston chamber may be definedradially between the piston and the housing 1105 and longitudinallybetween an upper seal (not shown) disposed between the housing 1105 andthe piston proximate the upper shoulder and a lower seal (not shown)disposed between the housing 1105 and the piston proximate the lowershoulder. A piston seal (not shown) may also be disposed between thepiston shoulder and the housing 1105. Hydraulic fluid may be disposed inthe piston chamber. Each end of the piston chamber may be in fluidcommunication with a respective hydraulic coupling (not shown) via arespective hydraulic passage (not shown, see 309 p) formedlongitudinally through a wall of the housing 1105.

The driver may be disposed between the mandrel 1110 and the housing 1105and longitudinally movable relative to the housing 1105 between an upperposition and a lower position. The driver may be rotationally connectedto the housing 1105 and longitudinally movable relative thereto. Thedriver may interact with the mandrel 1110 by having a helical profileformed in an inner surface thereof mated with the mandrel helicalprofile. The driver may be longitudinally connected to the piston orformed integrally therewith. The helical profiles may allow the driverto longitudinally translate while not rotating while the mandrel 1110 isrotated by the shifting tool 1175 and not translated. The driver mayalso interact with the sleeve 1125. As the sleeve 1125 is moved from theupper position to the lower position by the spring 1130, a bottom of thesleeve may engage a top of the driver, thereby stopping movement of thesleeve at the lower position.

Two power subs 1100 (only one shown) may be hydraulically connected tothe isolation valve 50 in a three-way configuration such that each ofthe power sub pistons are in opposite positions and operation of one ofthe power subs 1100 will operate the isolation valve 50 between the openand closed positions and alternate the other power sub 1100. This threeway configuration may allow each power sub 1100 to be operated in onlyone rotational direction and each power sub 1100 to only open or closethe isolation valve 50. Respective hydraulic couplings of each power sub1100 and the isolation valve 50 may be connected by a conduit, such astubing (not shown).

The shifting tool 1175 may include a opener or closer tag 1175 t,similar to the opener or closer tags 601 o,c, embedded in an outersurface of the body 1175 b. The embedded tag 1175 c may be locatedproximate to an end of the ribs 1175 r. The shifting tool 1175 mayfurther include a protector 1175 p formed proximate to the tag 1175 t onan opposite end thereof, thereby straddling the tag to prevent damagethereto. The drill string 1050 may further include a second shiftingtool (not shown) similar or identical to the shifting tool 1100 exceptfor including the other of the opener and closer tag. Alternatively, oneof the tags 250 a,p,w may be pumped through the drill string 1050instead of using the embedded tags 1175 t and the same shifting tool maybe used to operate both power subs.

In operation, once the actuator 1150 receives the instruction signalfrom the tag 1175 c, the microprocessor may operate the linear actuator1152 to retract the lock sleeve 1153, thereby releasing the sleeve 1125.The spring 1130 may push the sleeve 1125 and extend the fingers 1110 f,thereby engaging the lugs 1110

with the ribs 1125 r. The drill string 1050 may be rotated, therebyrotating the shifting tool 1175. If the lugs 1110

are misaligned, the lugs may engage the ribs 1175 r as rotation of theshifting tool 1175 begins. Rotation of the shifting tool 1175 may driverotation of the mandrel 1110. Rotation of the mandrel 1110 maylongitudinally drive the driver upward due to interaction of the helicalprofiles. The driver may pull the piston longitudinally to the upperposition, thereby pumping hydraulic fluid to the isolation valve 50 andopening or closing the valve. As the driver moves upward, the driver maypush the sleeve 1125 toward the upper shoulder 1151 u until the sleeveprofile 1125 g engages the latch 1154 and the cams 1110 c engage theslots 1125 f, thereby retracting the fingers 1110 f. Retraction of thefingers 1110 f may ensure that continued rotation of the shifting tool1175 does not damage the power sub 1100 and the isolation valve 50. Themicroprocessor may then detect engagement of the profile 1125 g with thelatch 1154 and engage the lock 1154.

Once the other power sub is operated by the respective shifting tool,fluid returning from the isolation valve 50 may push the pistondownward, thereby longitudinally pulling the driver to the lowerposition. The mandrel 1110 may freely counter-rotate to facilitate themovement. The power sub 1100 may now be reset for further operation.

Additionally, any of the chargers 600, 650, 575 may be used to chargethe battery 1131 and a capacitor may be used instead of or in additionto the battery as discussed above. Alternatively, the power sub 1100 mayinclude a protector sleeve covering the fingers 1110 f in the retractedposition and retracting when the fingers extend so as not to obstructextension of the fingers. Alternatively, slips and a cone, drag blocks,dogs, or radial pistons may be used instead of the fingers 1110 f.Alternatively, the fingers 1110 f may longitudinally connect the mandrel1110 and the shifting tool 1175 and the power sub 1100 may be operatedby longitudinal movement of the shifting tool.

FIG. 13A is a cross-section of a shifting tool 101 for actuating theisolation assembly between the positions, according to anotherembodiment of the present invention. The shifting tool 101 may besimilar to the shifting tool 100 except for including a manual override.The manual override may include a piston 111 (instead of the piston 110)and the hydraulic lock 151 (instead of the hydraulic lock 150). Thepiston 111 may be similar to the piston 110 except that a seat 111 b maybe formed in an inner surface thereof for receiving a blocking member,such as a ball 170. The lock 151 may be similar to the lock 150 exceptthat a frangible member, such as a rupture disk 164, may replace thecheck valve 154. Alternatively, a pressure relief valve may be usedinstead of the rupture disk. In the event that the telemetry sub 200and/or the hydraulic lock 151 is damaged during drilling, the ball 170may be deployed, such as by pumping, through the drill string until theball lands on the seat 111 b. Pumping may continue, thereby exertingfluid force on the ball 170 and seat 111 b until pressure in the lowerchamber equals or exceeds a rupture pressure of the disk 164. Onceruptured, pressure in the lower chamber may be relieved by fluid flowingthrough the opened passage 159 c to the lower chamber, thereby alsounlocking the piston 111 to move downward and extending the drivers intoengagement with any of the power subs, discussed above. The isolationvalve may then be closed and the drill string retrieved to the rig.

FIGS. 13B and 13C illustrate a portion of an isolation valve 501 in theclosed position, according to another embodiment of the presentinvention. The isolation valve 501 may be similar to the isolation valve500 except for including a manual override. The manual override mayinclude an actuator 551 (instead of the actuator 550) and a biasingmember, such as a coil spring 513. The spring 513 may be added betweenthe flow tube 515 and the housing 505. The spring 513 may be disposedagainst a top of the housing section 505 d and a shoulder of the flowtube 515, thereby biasing the flow tube away from the flapper 520. Theactuator 551 pump may generate sufficient pressure to overcome the biasof the spring when opening the valve 501. A profile 515 p may be formedin an inner surface of the flow tube 515. The actuator 551 may besimilar to the actuator 550 except that a frangible member, such as arupture disk 564, may be added. Alternatively, a pressure relief valvemay be used instead of the rupture disk. The rupture disk 564 may be influid communication with the hydraulic passages 553 u,

. A redundant shifting tool (not shown) may be assembled as part of thedrill string.

In the event that the actuator 551 is damaged during drilling, theshifting tool may be extended into engagement with the profile 515 p.The drill string may be pulled upward from the drilling rig, therebypulling the flow tube 515. Pressure may increase in the passage 553<until the pressure equals or exceeds the rupture pressure of the disk564. Once ruptured, pressure in the upper passage may be relieved byfluid flowing through the ruptured disk 564 to the lower passage,thereby also unlocking the flow tube 515 to move upward and allowing theflapper spring 521 to close the flapper 520. The drill string may thenbe retrieved to the rig.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A downhole power tool, comprising: a housing; a mandrel disposed inthe housing; a first sleeve having a profile disposed in the housing,wherein the first sleeve is movable relative to the housing from a firstposition to a second position; and an actuator having a lock and alatch, wherein the latch engages the profile to retain the first sleevein the first positon, and wherein the lock is configured to retain thelatch in engagement with the profile in a locked position and to allowthe latch to disengage from the profile when in an unlocked position. 2.The downhole power tool of claim 1, wherein the mandrel includes aplurality of collet fingers movable from a retracted position to anextended position.
 3. The downhole power tool of claim 2, wherein theplurality of collet fingers are in the extended position when the firstsleeve is in the second position.
 4. The downhole power tool of claim 3,wherein each collet finger of the plurality of collet fingers has a cam,and wherein each cam of the plurality of collet fingers is disposed in acorresponding slot of a plurality of slots formed in the first sleevewhen the plurality of collet fingers are in the retracted position. 5.The downhole power tool of claim 4, wherein each slot has an inclinedsurface configured to engage with an inclined surface of thecorresponding cam.
 6. The downhole power tool of claim 1, the actuatorfurther comprising an antenna configured to receive an instructionsignal, wherein the lock moves from the locked position to the unlockposition in response to the instruction signal.
 7. The downhole powertool of claim 6, wherein the instruction signal is received from a tagembedded in a shifting tool that is inserted into the power sub.
 8. Thedownhole power tool of claim 1, wherein the lock is a linear actuatorand further comprising a lock sleeve, wherein the lock sleeve is engagedwith the latch in the locked position and wherein the lock sleeve isdisengaged with the latch in the unlocked position.
 9. The downholepower tool of claim 1, wherein the latch is a collet.
 10. A system,comprising: a shifting tool having a plurality of ribs; and a downholepower tool having: a housing; a mandrel disposed in the housing, themandrel having a plurality of collet fingers movable from a retractedposition to an extended position; and a first sleeve disposed betweenthe housing and the mandrel and movable from a first position to asecond position; wherein the plurality of collet fingers are in theretracted positon when the first sleeve is in the first positon, theplurality of collet fingers are in the extended positon when the firstsleeve is in the second position, and wherein the plurality of colletfingers are engaged with the plurality of ribs when in the extendedposition.
 11. The system of claim 10, wherein each collet finger of theplurality of collet fingers has a cam, and wherein each cam of theplurality of collet fingers is disposed in a corresponding slot of aplurality of slots formed in the first sleeve when the plurality ofcollet fingers are in the retracted position.
 12. The system of claim10, the downhole power tool further comprising: the first sleeve havinga profile; and an actuator having: a latch configured to engage theprofile to retain the first sleeve in the first positon and disengagefrom the profile to allow the first sleeve to move to the secondposition; a lock configured to retain the latch in engagement with theprofile in a locked position and to allow the latch to disengage fromthe profile when in an unlocked position.
 13. They system of claim 12,the actuator further comprising an antenna configured to receive aninstruction signal, wherein the lock moves from the locked position tothe unlock position in response to the instruction signal.
 14. Thesystem of claim 13, wherein the instruction signal is received from atag embedded in the shifting tool.
 15. The system of claim 12, whereinthe lock is a linear actuator and further comprising a lock sleeve,wherein the lock sleeve is engaged with the latch in the locked positionand wherein the lock sleeve is disengaged with the latch in the unlockedposition.
 16. A method of operating a downhole power tool, comprising:inserting a shifting tool having a plurality of ribs into the downholepower tool, the downhole power tool having a latch, a lock, a sleeve,and a mandrel having a plurality of collet fingers; and releasing thelock in response to an instruction signal, wherein the release of thelock allows the latch to disengage from a profile of the sleeve causingthe sleeve to move from a first positon to a second position, whereinthe plurality of collet fingers engage the plurality of ribs of theshifting tool when the sleeve is in the second position.
 17. The methodof operating the downhole power tool of claim 16, further comprising:rotating the shifting tool to rotate the mandrel.
 18. The method ofoperating the downhole power tool of claim 16, wherein the instructionsignal is received from a tag embedded in the shifting tool.
 19. Themethod of operating the downhole power tool of claim 16, furthercomprising moving the sleeve from the second position to the firstposition to reengage the latch with the profile of the sleeve.
 20. Themethod of operating the downhole power tool of claim 19, furthercomprising relocking the lock to retain the latch in engagement with theprofile of the sleeve.